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ARTICLE XVII CERTAIN TRANSACTIONS IN CONNECTION WITH THE INITIAL PUBLIC OFFERING

Section 17.1

Non-Pro Rata Redemption of Common Units

EXHIBIT A Certificate Evidencing Common Units Representing Limited Partner Interests in American Midstream Partners, LP

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.

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.

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:


	•	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.

Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and lenders, to assess:


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

	•	the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;

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

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

The economic rationale behind management’s use of adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.

The GAAP measure most directly comparable to adjusted EBITDA is net income. Our non-GAAP financial measure of adjusted EBITDA should not be considered as an alternative to net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Management compensates for the limitations of adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

The following table presents a reconciliation of adjusted EBITDA to net income (loss) attributable to our unitholders for each of the periods indicated:


												American Midstream
												Partners, LP
												and Subsidiaries
	American Midstream Partners Predecessor											(Successor)
												Period from
												August 20,
												2009
	Year			Year			Year		10 Months			(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
	(unaudited)																	(unaudited)
	(in thousands)

Reconciliation of Adjusted EBITDA to Net Income (Loss)
Net income (loss)	$	(3,506	)	$	(9,046	)	$	2,728	$	(5,337	)	$	(6,992	)	$	(8,644	)	$	(1,454	)	$	(3,510	)
Add:
Depreciation expense		9,917			12,500			13,481		12,630			2,978			20,013			4,966			5,037
Interest expense		8,469			8,527			5,747		3,728			910			5,406			1,357			1,264
Unrealized (gain) loss on commodity derivatives		—			—			—		—			—			—			—			3,500
Non-cash equity compensation expense		—			—			—		—			150			1,185			254			335
One-time transaction costs		—			—			—		—			6,404			303			74			288

Adjusted EBITDA	$	14,880		$	11,981		$	21,956	$	11,021		$	3,450		$	18,263		$	5,197		$	6,914

Gross Margin

We define gross margin as the sum of segment gross margin in our Gathering and Processing segment and segment gross margin in our Transmission segment. We define segment gross margin in our Gathering and Processing segment as revenue generated from gathering and processing operations less the cost of natural gas, NGLs and condensate purchased. We define segment gross margin in our Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less the cost of natural gas purchased in connection with fixed-margin arrangements. Gross margin is included as a supplemental disclosure because it is a primary performance measure used by our management as it represents the results of service fee revenue and cost of sales, which are key components of our operations. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. Effective January 1, 2011, we changed our gross margin and segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. For the quarter ended March 31, 2011, $3.5 million in unrealized losses were excluded from the Gathering and Processing segment gross margin. For a reconciliation of gross margin to net income, its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 18 to our audited consolidated financial statements and Note 12 to our unaudited consolidated financial statements included elsewhere in this prospectus.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

You should read the following discussion of the financial condition and results of operations of American Midstream Partners, LP and its subsidiaries in conjunction with the historical consolidated financial statements and related notes of American Midstream Partners, LP and the historical combined financial statements and related notes of our Predecessor included elsewhere in this prospectus. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information.

Overview

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 own three processing facilities that produced an average of approximately 34.1 Mgal/d and 55.1 Mgal/d of gross NGLs for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. In addition, in connection with our elective processing arrangements, we contract for processing capacity at a third-party plant where we have the option to process natural gas that we purchase. Under these arrangements, we sold an average of approximately 28.1 Mgal/d and 35.0 Mgal/d of net equity NGL volumes for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. 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.

Our Operations

We manage our business and analyze and report our results of operations through two business segments:


	•	*Gathering and Processing.* Our Gathering and Processing segment provides “wellhead to market” services for natural gas to producers of natural gas and oil, which include transporting raw natural gas from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas as well as NGLs to various markets and pipeline systems.

	•	*Transmission.* Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.

Gathering and Processing Segment

Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas we gather and process, the commercial terms in our current contract portfolio and

natural gas, NGL and condensate prices. We gather and process natural gas primarily pursuant to the following arrangements:


	•	*Fee-Based Arrangements.* Under these arrangements, we generally are paid a fixed cash fee for gathering and transporting natural gas.

	•	*Fixed-Margin Arrangements.* Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. By entering into back-to-back purchases and sales of natural gas, we are able to lock in a fixed-margin on these transactions. We view the segment gross margin earned under our fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements.


	•	*Percent-of-Proceeds Arrangements.* Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs at market prices. Where we provide processing services at the processing plants that we own or obtain processing services for our own account in connection with our elective processing arrangements, such as under our Toca contract, we generally retain and sell a percentage of the residue natural gas and resulting NGLs. Please read “Business — Gathering and Processing Segment — Gloria System.”

Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in volumes and, thus, a decrease in our fee-based and fixed-margin gross margin. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. Under our typical percent-of-proceeds arrangement, our gross margin is directly impacted by the commodity prices we realize on our share of natural gas and NGLs received as compensation for processing raw natural gas. However, our percent-of-proceeds arrangements also often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. We further seek to mitigate our exposure to commodity price risk through our hedging program. Please read “ — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

Transmission Segment

Results of operations from our Transmission segment are determined primarily by capacity reservation fees from firm transportation contracts and, to a lesser extent, the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:


	•	*Firm Transportation Arrangements.* Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us.

	•	*Interruptible Transportation Arrangements.* Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped.

	•	*Fixed-Margin Arrangements.* Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements.

The gross margin we earn from our transportation activities is directly related to the capacity reservation on, and actual volume of natural gas that flows through, our systems, neither of which is directly dependent on commodity prices. However, a sustained decline in market demand could result in a decline in volumes and, thus, a decrease in our commodity-based gross margin under firm transportation contracts or gross margin under our interruptible transportation and fixed-margin contracts.

Contract Mix

Set forth below is a table summarizing our average contract mix for the year ended December 31, 2010 and the quarter ended March 31, 2011:


	Year Ended					Quarter Ended
	December 31, 2010					March 31, 2011
	Segment		Percent of			Segment		Percent of
	Gross		Segment			Gross		Segment
	Margin		Gross Margin			Margin		Gross Margin
	(in millions)					(in millions)

Gathering and Processing
Fee-based	$	6.5		26.4	%	$	2.0		24.6	%
Fixed-margin		4.9		19.9			1.2		14.4
Percent-of-proceeds		13.2		53.7			5.0		61.0

Total	$	24.6		100	%	$	8.2		100	%

Transmission
Firm transportation	$	10.8		80.0	%	$	3.4		83.0	%
Interruptible transportation		2.0		14.8			0.5		12.6
Fixed-margin		0.7		5.2			0.2		4.4

Total	$	13.5		100	%	$	4.1		100	%

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include throughput volumes, gross margin and direct operating expenses on a segment basis, and adjusted EBITDA and distributable cash flow on a company-wide basis.

Throughput Volumes

In our Gathering and Processing segment, we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas and obtain new supplies is impacted by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to or near our gathering systems, (ii) our ability to compete for volumes from successful new wells in the areas in which we operate, (iii) our ability to obtain natural gas that has been released from other commitments and (iv) the volume of natural gas that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

In our Transmission segment, the majority of our segment gross margin is generated by firm capacity reservation fees, as opposed to the actual throughput volumes, on our interstate and intrastate pipelines. Substantially all of this segment gross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to pursue new shipper opportunities.

Gross Margin and Segment Gross Margin

Gross margin and segment gross margin are the primary metrics that we use to evaluate our performance. See “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.” We define segment gross margin in our Gathering and Processing segment as revenue generated from gathering and processing operations less the cost of natural gas, NGLs and condensate purchased. Revenue includes revenue generated from fixed fees associated with the gathering and treating of natural gas and from the sale of natural gas, NGLs and condensate resulting from gathering and processing activities under fixed-margin and percent-of-proceeds arrangements. The cost of natural gas, NGLs and condensate includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to percent-of-proceeds arrangements and the cost of natural gas purchased for our own account, including pursuant to fixed-margin arrangements.

We define segment gross margin in our Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

Effective January 1, 2011, we changed our gross margin and segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. For the quarter ended March 31, 2011, $3.5 million in unrealized losses were excluded from the Gathering and Processing segment gross margin.

Direct Operating Expenses

Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, lost and unaccounted for gas and contract services comprise the most significant portion of our operating expenses. These expenses are relatively stable and largely independent of throughput volumes through our systems, but may fluctuate depending on the activities performed during a specific period.

Adjusted EBITDA and Distributable Cash Flow

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. See “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.” Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as adjusted EBITDA plus interest income, less cash paid for interest expense and maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances. Adjusted EBITDA and distributable cash flow are used as supplemental measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:


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

	•	the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;

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

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

Note About Non-GAAP Financial Measures

Gross margin, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations. Net income is the GAAP measure most directly comparable to each of gross margin and adjusted EBITDA. The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider any of gross margin, adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Items Affecting the Comparability of Our Financial Results

Our historical results of operations for the periods presented and those of our Predecessor may not be comparable, either to each other or to our future results of operations, for the reasons described below:


	•	Since we acquired our assets from Enbridge effective November 1, 2009, the financial and operational data for 2009 that is discussed below is generally bifurcated between the period that our Predecessor owned those assets and the period from our acquisition through the end of the year. Moreover, there is some overlap between these two periods resulting from the fact that we were formed on August 20, 2009, which was prior to the acquisition on November 1, 2009. As a result, the 2009 period that our Predecessor owned and operated the assets is the ten months ended October 31, 2009, while the successor 2009 period begins with our inception on August 20, 2009 and ends on December 31, 2009. Although we incurred costs associated with our formation and the acquisition of our assets from Enbridge of $6.4 million, we had no material operations until November 1, 2009.

	•	The historical combined financial statements and related notes of our Predecessor:


	•	are presented on a combined rather than a consolidated basis. The principal difference between consolidated and combined financial statements is that consolidated financial statements do not reflect transactions and investments between consolidated subsidiaries or between those subsidiaries and the parent entity, showing instead a view of the parent entity and its consolidated subsidiaries as a whole; and

	•	reflect the operation of our assets with different business strategies and as part of a larger business rather than the stand-alone fashion in which we operate them. Please read “Business — Business Strategies.”


	•	SG&A expenses of our Predecessor during periods in which we did not own or operate our assets were allocated expenses from a much larger parent entity and may not represent SG&A expenses required to actually operate our assets as we intend. In addition, we adopted an LTIP in connection with our formation in 2009, and our SG&A expenses for the year ended December 31, 2010 and for the quarter ended March 31, 2011 included $1.7 million and $0.5 million, respectively, of cash and non-cash expenses associated with grants pursuant to our LTIP.

	•	Initially, we anticipate incurring approximately $2.3 million of annual incremental general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly SEC 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; director and officer liability insurance costs; and director compensation.


	•	In connection with our formation and the acquisition of our assets from Enbridge, we incurred transaction expenses of approximately $6.4 million. These transaction expenses are included in our historical consolidated financial statements for the period from August 20, 2009 to December 31, 2009.

	•	In connection with the acquisition of our assets from Enbridge, effective November 1, 2009:


	•	we put in place stand-alone insurance policies customary for midstream partnerships, which had the effect of increasing our direct operating expenses;

	•	we initiated a comprehensive review of the integrity management program that we inherited when we acquired our assets. Following this review, we concluded that there were sixteen high consequence areas that required further testing pursuant to DOT regulations;

	•	one of our subsidiaries entered into an advisory services agreement with certain affiliates of AIM Midstream Holdings, which resulted in higher SG&A expenses during the periods after that acquisition. Please read “Certain Relationships and Related Party Transactions — Agreements with Affiliates.” At the closing of this offering, we will pay $2.5 million to those affiliates to terminate this agreement; and

	•	we recorded our assets at fair value, which was less than our Predecessor’s book value of those assets, and their useful lives were also decreased, which had the net effect of increasing the depreciation expense associated with our assets after the acquisition date.


	•	Interest expense of our Predecessor was an allocated expense from our Predecessor’s publicly traded parent entity. In addition, we incurred indebtedness to finance our acquisition of our assets from Enbridge, which increased our interest expense after the acquisition date.

	•	After our acquisition of our assets from Enbridge, we initiated a hedging program comprised of NGL puts and swaps, as well as interest rate caps, that we account for using mark-to-market accounting. These amounts are included in our historical consolidated financial statements and related notes as unrealized/realized gain (loss) from risk management activities.

	•	In December 2010, we completed an interconnect between our Lafitte pipeline and a pipeline on the TGP interstate system. This interconnect enables us to purchase natural gas from producers on the TGP system and deliver it to the Alliance Refinery and the Toca processing plant, which will enable us to process substantially more natural gas under our elective processing arrangements.

General Trends and Outlook

We expect our business to continue to be affected by the key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Outlook

Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic downturn that led to a decline in worldwide energy demand. During this same period, North American oil and natural gas supply was increasing as a result of the rise in domestic unconventional production. The combination of lower energy demand due to the economic downturn and higher North American oil and natural gas supply resulted in significant declines in oil, NGL and natural gas prices. While oil and NGL prices began to increase steadily in the second quarter of 2009, natural gas prices remained depressed and volatile throughout 2009 and 2010 in comparison to much of 2007 and 2008 due to a continued increase in natural gas supply despite weaker offsetting demand growth. The outlook for a worldwide economic recovery in 2011 remains uncertain, and the timing of a recovery in worldwide demand for energy is difficult to predict. As a result, we expect natural gas prices to remain relatively low in the near term.

Notwithstanding the ongoing volatility in commodity prices, there has been a recent resurgence in the level of acquisition and divestiture activity in the midstream energy industry and we expect that trend to

continue. In particular, we believe that opportunities to acquire midstream energy assets from third parties that fulfill our strategic objectives will continue to arise in the foreseeable future.

Supply and Demand Outlook for Natural Gas and Oil

Natural gas and oil continue to be critical components of energy consumption in the United States. According to the U.S. Energy Information Administration, or EIA, annual consumption of natural gas in the U.S. was approximately 24.1 trillion cubic feet, or Tcf, in 2010, compared to approximately 22.8 Tcf in 2009, representing an increase of approximately 5.7%. Domestic production of natural gas grew from approximately 21.6 Tcf in 2009 to approximately 22.6 Tcf in 2010, or a 4.4% increase. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States, representing approximately 58% of the total natural gas consumed in the United States during 2010. In particular, based on a report by the EIA, industrial natural gas demand is expected to grow from 7.3 Tcf in 2009 to 9.4 Tcf in 2020 as a result of an expected recovery in industrial production.

According to the EIA, domestic crude oil production was approximately 5.5 million barrels per day, or MMBbl/d, in 2010, compared to approximately 5.4 MMBbl/d in 2009, representing an increase of approximately 2.8%. Domestic crude oil production is expected to continue to increase over time primarily due to improvements in technology that have enabled U.S. onshore producers to economically extract sources of supply, such as secondary and tertiary oil reserves and unconventional oil reserves, that were previously unavailable or uneconomic.

We believe that current oil and natural gas prices and the existing demand for oil and natural gas will continue to result in ongoing oil- and natural gas-related drilling in the United States as producers seek to increase their production levels. In particular, we believe that drilling activity targeting natural gas with modest to high NGL content, such as on our Gloria system, and targeting oil with associated natural gas, such as on our Bazor Ridge system, will remain active. Although we anticipate continued exploration and production activity in the areas in which we operate, fluctuations in energy prices can affect natural gas production levels over time as well as the timing and level of investment activity by third parties in the exploration for and development of new oil and natural gas reserves. We have no control over the level of oil and natural gas exploration and development activity in the areas of our operations.

Impact of Interest Rates

The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on floating rate credit facilities and future offerings in the debt capital markets could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes.

Impact of Bazor Ridge Emissions Matter

With respect to our Bazor Ridge processing plant, we recently determined that (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. Please read “Business — Environmental Matters — Air Emissions” for more information about these matters.

We generally emit SO₂ from our Bazor Ridge plant only in connection with the flaring of natural gas in situations where the plant is not operational. We do not believe that the elevated levels of SO₂ emissions that the plant experienced in 2009 and 2010 resulted from problems with or inefficiencies in our flaring procedures. In response to our discovery of these exceedances and violations, however, we are considering procedural changes to reduce flaring and resulting SO₂ emissions when the plant becomes inoperable. We have no plans to install any additional emission controls at our Bazor Ridge plant, as we are unaware of any such controls that could reasonably reduce our SO₂ emissions. In addition, we are not aware of further operational restrictions or limitations that would reasonably reduce our SO₂ emissions.

Because we flare natural gas at our Bazor Ridge plant only in situations where the plant is not operational, and thus not generating revenue, we do not expect that the potential procedural changes at the Bazor Ridge plant or any operational restrictions or limitations imposed on the plant as a result of these exceedances and violations would materially impact our revenues or results of operations. Please read “— Liquidity and Capital Resources — Impact of Bazor Ridge Emissions Matter” for information about the potential effect of these matters on our liquidity and capital resources.

In addition to the potential procedural changes, we may seek an increase in the level of permitted SO₂ emissions in order to avoid exceeding our Title V Air Permit in the future. This process involves public comment periods and a technical review. If the application is successful, an amended Title V Air Permit would be issued. This process typically takes approximately nine months to complete. We do not expect that we will be required to suspend or curtail our operations at the Bazor Ridge plant during any such application process.

We do not expect to be required to obtain a PSD permit for the Bazor Ridge plant, as our operation of the plant in 2010 produced SO₂ emissions below the threshold requiring such a permit and we expect to continue to operate in this manner. Should we be required to obtain a PSD permit, however, the application process requires modeling, an impact analysis of emissions from the Bazor Ridge plant and a review of possible emission control equipment. The process involves public comment periods and a technical review. If the application is successful, a permit containing site-specific emission limits, as well as monitoring and record-keeping requirements, is issued. The complete process typically takes a year or more to complete. Even if we are required to obtain a PSD permit, we do not expect that we will be required to suspend or curtail our operations at the Bazor Ridge plant during any such application process.

Results of Operations — Combined Overview

The following table and discussion presents certain of our historical consolidated financial data and the historical combined financial data of our Predecessor for the periods indicated.

We refer to the results of our Predecessor’s operations for the period from January 1, 2009 to October 31, 2009 as the 2009 Predecessor Period and to our operating results for the period from August 20, 2009 to December 31, 2009 as the 2009 Successor Period.

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, but we incurred certain fees and expenses totaling $6.4 million associated with our formation and acquisition of our assets from Enbridge.

The financial data for the 2009 Predecessor Period and the year ended December 31, 2008 represent periods of time prior to our acquisition of our assets. During these periods, our Predecessor owned and operated our operating assets. As such, the results of operations for these periods do not necessarily represent the results of operations that would have been achieved during the period had we owned and operated our assets.

The results of operations by segment are discussed in further detail following this combined overview.


							American Midstream
	American Midstream Partners						Partners, LP and Subsidiaries
	Predecessor						(Successor)
							Period from
							August 20,
	Year			10 Months			2009			Year			Quarter			Quarter
	Ended			Ended			(Inception Date) to			Ended			Ended			Ended
	December 31,			October 31,			December 31,			December 31,			March 31,			March 31,
	2008			2009			2009			2010			2010			2011
							(in thousands)
Statement of Operations Data:
Revenue	$	366,348		$	143,132		$	32,833		$	211,940		$	54,712		$	67,265
Unrealized gain (losses) 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	)
Interest expense		5,747			3,728			910			5,406			1,357			1,264
Other (income) expenses		(854	)		(24	)		—			—			—			—

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

Other Financial Data:
Adjusted EBITDA(2)	$	21,956		$	11,021		$	3,450		$	18,263		$	5,197		$	6,914
Gross margin(3)	$	43,143		$	29,905		$	6,240		$	38,119		$	9,748		$	12,312


(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)		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.”

(3)		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.”

Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010

Revenue. Our total revenue in the quarter ended March 31, 2011 was $63.8 million compared to $54.7 million in the quarter ended March 31, 2010. This increase of $9.1 million was primarily due to higher realized NGL prices in our Gathering and Processing segment and a new fixed-margin contract in our Transmission segment. This increase was partially offset by lower realized natural gas prices in our Gathering and Processing segment.

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate in the quarter ended March 31, 2011 were $55.0 million compared to $45.0 million in the quarter ended March 31, 2010. This increase of $10.0 million was primarily due to higher realized NGL prices in our

Gathering and Processing segment and a new fixed-margin contract in our Transmission segment. This increase was partially offset by lower realized natural gas prices in our Gathering and Processing segment.

Gross Margin. Gross margin in the quarter ended March 31, 2011 was $12.3 million compared to $9.7 million in the quarter ended March 31, 2010. This increase of $2.6 million was primarily due to higher realized NGL prices and increased plant inlet volumes in our Gathering and Processing segment.

Direct Operating Expenses. Direct operating expenses in the quarter ended March 31, 2011 were $3.1 million compared to $2.7 million in the quarter ended March 31, 2010. This increase of $0.4 million was primarily due to increased repairs and maintenance as well as lease and rent expenses. This increase was partially offset by a decrease in personnel costs.

Selling, General and Administrative Expenses. SG&A expenses in the quarter ended March 31, 2011 were $2.7 million compared to $2.1 million in the quarter ended March 31, 2010. This increase of $0.6 million was primarily due to increased information technology expenses, increased employment-related expenses and increased costs associated with our LTIP.

Depreciation Expense. Depreciation expense in the quarter ended March 31, 2011 was $5.0 million compared to $5.0 million in the quarter ended March 31, 2010.

Year Ended December 31, 2010 Compared to the 2009 Successor Period and the 2009 Predecessor Period

Revenue. Our total revenue in 2010 was $211.9 million compared to $32.8 million and $143.1 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to higher realized NGL prices in our Gathering and Processing segment and a new fixed-margin contract in our Transmission segment. Under our fixed-margin contracts, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical quantity of natural gas at delivery points on our systems at the same undiscounted index price. This increase was partially offset by lower throughput and processing volumes in our Gathering and Processing segment and lower NGL production.

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for 2010 were $173.8 million compared to $26.6 million and $113.2 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily the result of a new fixed-margin contract in our Transmission segment and higher realized NGL prices in our Gathering and Processing segment, and was partially offset by lower throughput and processing volumes in our Gathering and Processing segment.

Gross Margin. Gross margin in 2010 was $38.1 million, compared to $6.2 million and $29.9 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to higher realized NGL prices in our Gathering and Processing segment, which positively impacted the segment gross margin associated with our percent-of-proceeds arrangements, and was partially offset by lower throughput and processing volumes in our Gathering and Processing segment. In addition, segment gross margin in our Transmission segment was higher in 2010 due to increased throughput volumes on our regulated pipelines as a result of colder weather. The increases in revenue and purchases of natural gas, NGLs and condensate that were driven by higher realized commodity prices and the new fixed-margin contract in our Transmission segment had minimal impact on gross margin.

Direct Operating Expenses. Direct operating expenses in 2010 were $12.2 million, compared to $1.6 million and $10.3 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to higher fixed costs, such as insurance and higher maintenance expenses that we incurred following our acquisition of our assets in our Transmission segment, partially offset by lower outside services costs in our Gathering and Processing segment.

Selling, General and Administrative Expenses. SG&A expenses in 2010 were $8.9 million, compared to $1.3 million and $8.6 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. SG&A expenses include LTIP expenses of $1.7 million and $0.2 million in 2010 and the 2009 Successor Period, respectively. Because we adopted the LTIP in November 2009, there were no LTIP expenses in the 2009

Predecessor Period. The decrease in SG&A expenses was a result of our incurrence of actual SG&A expenses compared to the historical allocation of SG&A expenses by the owner of our Predecessor, but was offset in part by increases in LTIP expenses due to an increase in the number of phantom units granted in 2010.

One-Time Transaction Expenses. We incurred approximately $6.4 million of one-time expenses, including legal, consulting and accounting fees in the 2009 Successor Period in connection with our acquisition of our assets. An additional $0.3 million was recorded in 2010 primarily related to Predecessor audit fees and remaining asset valuation costs.

Depreciation Expense. Depreciation expense was $20.0 million in 2010 compared to $3.0 million and $12.6 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. We recorded our assets at fair value, which was less than our Predecessor’s book value of those assets, and their useful lives were also decreased, which had the net effect of increasing the depreciation expense associated with our assets after the acquisition date. The increase in depreciation expense from 2009 to 2010 is attributable to those adjustments.

The 2009 Successor Period and the 2009 Predecessor Period Compared to Year Ended December 31, 2008

Revenue. Our total revenue was $32.8 million and $143.1 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $366.3 million for 2008. This decrease was primarily due to lower realized natural gas, NGL and condensate prices as well as lower plant inlet volumes and NGL production in our Gathering and Processing segment, although this decrease was partially offset by an increase in volumes gathered pursuant to fee-based and fixed-margin arrangements.

Purchases of Natural Gas, NGLs and Condensate. Our total purchases of natural gas, NGLs and condensate were $26.6 million and $113.2 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $323.2 million for 2008. This decrease was primarily due to lower throughput and processing volumes on our Bazor Ridge and Alabama Processing systems, as well as lower realized natural gas, NGL and condensate prices in our Gathering and Processing segment.

Gross Margin. Gross margin was $6.2 million and $29.9 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $43.1 million for 2008. This decrease was primarily due to lower realized natural gas and NGL prices, which negatively impacted the segment gross margin associated with our percent-of-proceeds arrangements in the Gathering and Processing segment, but was partially offset by higher throughput volumes on the Quivira system. In addition, segment gross margin was lower in the Transmission segment primarily as a result of the full-year impact of the change in the terms of a contract on our Midla system to more accurately reflect market rates between our Predecessor and an affiliate of our Predecessor.

Direct Operating Expenses. Direct operating expenses were $1.6 million and $10.3 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $13.4 million for 2008. This decrease was mainly due to the timing of our Predecessor’s 2008 expenditures in connection with a multi-year integrity management program.

Selling, General and Administrative Expenses. SG&A expenses were $1.3 million and $8.6 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $8.6 million for 2008. This increase in SG&A expenses was primarily due to additional costs allocated to our Predecessor during the 2009 Predecessor Period. Moreover, SG&A expenses include $0.2 million of LTIP expenses for the 2009 Successor Period. We adopted the LTIP in November 2009 and, as a result, there were no LTIP expenses for the 2009 Predecessor Period or any period prior to our formation.

Depreciation Expense. Depreciation expense was $3.0 million and $12.6 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $13.5 million for 2008. We recorded our assets at fair value, which was less than our Predecessor’s book value of those assets, and their useful lives

were also decreased, which had the net effect of increasing the depreciation expense associated with our assets after the acquisition date. This increase in depreciation expense was primarily due to those adjustments.

Segment Results

The table below contains key segment performance indicators related to our discussion of the results of operations of our segments.


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

Segment Financial and Operating Data:
*Gathering and Processing segment*
Financial data:
Revenue	$	349,861	$	132,957	$	27,857	$	158,455	$	46,624	$	48,084
Unrealized gain (loss) on commodity derivatives		—		—		—		—		—		(3,500	)
Total revenue		349,861		132,957		27,857		158,455		46,614		44,584

Purchases of natural gas, NGLs and condensate		322,507		112,933		24,159		133,860		40,526		39,917
Direct operating expenses	$	8,186	$	7,134	$	956	$	7,721	$	1,670	$	1,949
Other financial data:
Segment gross margin	$	27,354	$	20,024	$	3,698	$	24,595	$	6,098	$	8,167
Operating data:
Average throughput (MMcf/d)		179.2		211.8		169.7		175.6		164.3		242.8
Average plant inlet volume (MMcf/d)(1)		12.5		11.7		11.4		9.9		11.1		15.2
Average gross NGL production (Mgal/d)(1)		40.2		39.3		38.2		34.1		35.2		55.1
Average realized prices:
Natural gas ($/MMcf)	$	9.08	$	3.76	$	4.71	$	4.61	$	5.04	$	3.99
NGLs ($/gal)	$	1.36	$	0.70	$	1.05	$	1.08	$	1.13	$	1.18
Condensate ($/gal)	$	2.63	$	1.16	$	1.68	$	1.82	$	1.78	$	2.07
*Transmission segment*
Financial data:
Total revenue	$	16,487	$	10,175	$	4,976	$	53,485	$	8,088	$	19,181
Purchases of natural gas, NGLs and condensate		698		294		2,434		39,961		4,438		15,036
Direct operating expenses	$	5,237	$	3,197	$	638	$	4,466	$	1,022	$	1,109
Other financial data:
Segment gross margin	$	15,789	$	9,881	$	2,542	$	13,524	$	3,650	$	4,145

American Midstream

American Midstream Partners

Partners, LP and Subsidiaries

Predecessor

(Successor)

Period from

August 20,

Year

10 Months

2009

Year

Quarter

Ended

(Inception Date) to

Ended

December 31,

October 31,

December 31,

March 31,

2008

2009

2010

2011

(in thousands, except operating data)

Operating data:

Average throughput (MMcf/d)

336.2

357.6

381.3

350.2

360.6

446.0

Average firm transportation —
capacity reservation (MMcf/d)

627.3

613.2

701.0

677.6

702.8

762.1

Average interruptible transportation —
throughput (MMcf/d)

141.6

121.0

118.0

80.9

80.2

76.5


(1)		Excludes volumes and gross production under our elective processing arrangements.

Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010

Gathering and Processing Segment

Revenue. Segment revenue in the quarter ended March 31, 2011 was $48.1 million compared to $46.6 million in the quarter ended March 31, 2010. This increase was primarily due to increased throughput on our Gloria and Quivira systems, increased plant inlet volumes primarily at our Bazor Ridge processing plant, higher NGL sales and condensate volumes on our Bazor Ridge and Gloria Systems, and higher realized NGL prices. This increase was almost entirely offset by lower realized natural gas prices. Set forth below is a comparison of the volumetric and pricing data for the quarters ended March 31, 2011 and 2010 as well as a summary of the effect of the hedge transactions that we entered into in January 2011.


	•	Total natural gas throughput volumes on our Gathering and Processing segment were 242.8 MMcf/d in the quarter ended March 31, 2011 compared to 164.3 MMcf/d in the quarter ended March 31, 2010. Natural gas inlet volumes at our owned processing plants were 15.2 MMcf/d in the quarter ended March 31, 2011 compared to 11.1 MMcf/d in the quarter ended March 31, 2010. Gross NGL production volumes from our owned processing plants were 55.1 Mgal/d in the quarter ended March 31, 2011 compared to 35.2 Mgal/d in the quarter ended March 31, 2010.

	•	The average realized price of natural gas in the quarter ended March 31, 2011 was $3.99/Mcf, compared to $5.04/Mcf in the quarter ended March 31, 2010. The average realized price of NGLs in the quarter ended March 31, 2011 was $1.26/gal, compared to $1.13/gal in the quarter ended March 31, 2010. The average realized price of condensate in the quarter ended March 31, 2011 was $2.26/Mcf, compared to $1.78/gal in the quarter ended March 31, 2010.

	•	We entered into a series of hedge transactions in January 2011. These hedges had a net effect of ($3.5) million on our revenue related to unrealized losses for the quarter ended March 31, 2011. We had no hedges during the quarter ended March 31, 2010. For a discussion of our hedge positions, please read “— Quantitative and Qualitative Disclosures about Market Risk.”

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the quarter ended March 31, 2011 were $40.0 million compared to $40.5 million for the quarter ended March 31, 2010. This decrease of $0.5 million was primarily due to lower realized natural gas prices and partially offset by higher realized NGL prices and higher NGL and condensate volumes.

Segment Gross Margin. Segment gross margin for the quarter ended March 31, 2011 was $8.2 million compared to $6.1 million for the quarter ended March 31, 2010. This increase of $2.1 million was primarily due to increased throughput on our Gloria, Quivira and Bazor Ridge systems, higher realized NGL prices

which positively affected our Gloria and Bazor Ridge systems, and lower realized natural gas prices which positively impacted processing margins on our Gloria system. Segment gross margin for the Gathering and Processing segment represented 66.3% of our gross margin for the quarter ended March 31, 2011, compared to 62.6% for the quarter ended March 31, 2010.

Direct Operating Expenses. Direct operating expenses for the quarter ended March 31, 2011 were $2.0 million compared to $1.7 million for the quarter ended March 31, 2010. This increase of $0.3 million was primarily due to increased repairs and maintenance as well as lease and rent expenses and partially offset by a decrease in personnel costs.

Transmission Segment

Revenue. Segment revenue for the quarter ended March 31, 2011 was $19.2 million compared to $8.1 million for the quarter ended March 31, 2010. Total natural gas throughput on our Transmission systems for the quarter ended March 31, 2011 was 446.0 MMcf/d compared to 360.6 MMcf/d in the quarter ended March 31, 2010. This increase of $11.1 million in revenue was primarily due to the new fixed-margin contract in our Transmission segment under which we purchase and simultaneously sell the natural gas that we transport, as opposed to typical contracts in this segment in which we receive a fixed fee for transporting natural gas. Our hedges had no effect on segment revenue for the quarter ended March 31, 2011 and we had no hedges during the quarter ended March 31, 2010.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the quarter ended March 31, 2011 were $15.0 million compared to $4.4 million for the quarter ended March 31, 2010. This increase of $10.6 million was primarily due to the new fixed-margin contract in our Transmission segment.

Segment Gross Margin. Segment gross margin for the quarter ended March 31, 2011 was $4.1 million compared to $3.7 million for the quarter ended March 31, 2010. This increase of $0.4 million was primarily due to increased throughput on the MLGT and Midla systems, a new customer contract on one of our other, smaller systems and the realization of gross margin related to an increase in seasonally adjusted rates and reservation volumes as a result of colder weather on our AlaTenn System. Segment gross margin for the Transmission segment represented 33.7% of our gross margin for the quarter ended March 31, 2011, compared to 37.4% for the quarter ended March 31, 2010.

Direct Operating Expenses. Direct operating expenses for the quarter ended March 31, 2011 were $1.1 million compared to $1.0 million for the quarter ended March 31, 2010. This increase of $0.1 million was primarily due to increases to repairs and maintenance as well as lease and rent expenses.

Year Ended December 31, 2010 Compared to the 2009 Successor Period and the 2009 Predecessor Period

Gathering and Processing Segment

Revenue. Segment revenue for 2010 was $158.5 million compared to $27.9 million and $133.0 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This decrease was primarily due to decreased throughput and processing volumes on our Bazor Ridge system due to unplanned downtime caused by the pipeline rupture that occurred in April 2010. Please see “Risk Factors — Risks Related to Our Business — 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” for more information regarding the Bazor Ridge pipeline rupture. This decrease in revenue was partially offset by higher realized NGL prices across this segment. Set forth below is a comparison of the volumetric and pricing data for the year ended December 31, 2010, and the 2009 Successor Period and the 2009 Predecessor Period.


	•	Total natural gas throughput volumes on our Gathering and Processing segment were 175.6 MMcf/d in 2010 compared to 169.7 MMcf/d and 211.8 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively. Natural gas inlet volumes at our owned processing plants were 9.9 MMcf/d in 2010 compared to 11.4 MMcf/d and 11.7 MMcf/d in the 2009 Successor Period and the


		2009 Predecessor Period, respectively. Gross NGL production volumes from our owned processing plants were 34.1 Mgal/d in 2010 compared to 38.2 Mgal/d and 39.3 Mgal/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively.


	•	The average realized price of natural gas in 2010 was $4.61/MMcf, compared to $4.71/MMcf and $3.76/MMcf for the 2009 Successor Period and the 2009 Predecessor Period, respectively. The average realized price of NGLs in 2010 was $1.08/gal, compared to $1.05/gal and $0.70/gal for the 2009 Successor Period and the 2009 Predecessor Period, respectively.

	•	Our hedges had no effect on our revenue for the year ended December 31, 2010. We and our Predecessor had no hedges during the 2009 Successor Period and 2009 Predecessor Period, respectively.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for 2010 were $133.9 million compared to $24.2 million and $112.9 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This decrease in purchases of natural gas, NGLs and condensate was primarily driven by lower throughput and processing volumes on our Bazor Ridge system and lower fixed-margin volumes on our Lafitte system, partially offset by higher realized NGL prices across the segment.

Segment Gross Margin. Segment gross margin for 2010 was $24.6 million compared to $3.7 million and $20.0 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was largely due to higher realized NGL prices that had a positive impact on segment gross margin associated with percent-of-proceeds contracts on our Bazor Ridge and Gloria systems. In addition, natural gas prices were lower in 2010, which had a net positive impact on natural gas we processed under our elective processing arrangements. We also received additional segment gross margin associated with the construction of our Atmore processing plant that commenced operation in June 2010. This increase was partially offset by lower throughput volumes across most of our gathering systems due to well declines and reduced drilling activity due to lower natural gas prices as well as lower volumes on our Bazor Ridge system largely resulting from a pipeline rupture. Segment gross margin for the Gathering and Processing segment represented 64.5% of our gross margin for 2010, compared to 59.3% and 67.0%, respectively, for the 2009 Successor Period and the 2009 Predecessor Period.

Direct Operating Expenses. Direct operating expenses for 2010 were $7.7 million compared to $1.0 million and $7.1 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This decrease in direct operating expenses was primarily due to lower outside services costs.

Transmission Segment

Revenue. Segment revenue for 2010 was $53.5 million compared to $5.0 million and $10.2 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. Total natural gas throughput on our Transmission systems for 2010 was 350.2 MMcf/d compared to 381.3 MMcf/d and 357.6 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase in revenue was primarily due to the new fixed-margin contract in our Transmission segment under which we purchase and simultaneously sell the natural gas that we transport, as opposed to typical contracts in this segment in which we receive a fixed fee for transporting natural gas. This increase in revenue was partially offset by a decrease in volumes transported pursuant to fee-based and fixed-margin arrangements. Our hedges had no effect on our revenue for the year ended December 31, 2010. We and our Predecessor had no hedges during the 2009 Successor Period and 2009 Predecessor Period, respectively.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for 2010 were $40.0 million compared to $2.4 million and $0.3 million in the 2009 Successor Period and 2009 Predecessor Period, respectively. As part of our fixed-margin arrangements, we purchase natural gas, but not NGLs or condensate, in our Transmission segment. This increase was primarily due to the new fixed-margin arrangement on our MLGT system.

Segment Gross Margin. Segment gross margin for 2010 was $13.5 million compared to $2.5 million and $9.9 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to an increase in seasonally-adjusted rates and reservation volumes as a result of colder

weather in markets served by our AlaTenn and Midla systems. During periods of unseasonably cold weather, some shippers exceeded their maximum contract quantities and had to secure higher priced transport capacity to meet demand, thereby increasing our segment gross margin. Segment gross margin in our Transmission segment represented 35.5% of our gross margin for 2010, compared to 40.7% and 33.0% for the 2009 Successor Period and the 2009 Predecessor Period, respectively.

Direct Operating Expenses. Direct operating expenses for 2010 were $4.5 million compared to $0.6 million and $3.2 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. This increase was primarily due to incremental insurance costs that we had to incur and allocate to our assets.

The 2009 Successor Period and the 2009 Predecessor Period Compared to Year Ended December 31, 2008

Gathering and Processing Segment

Revenue. Segment revenue was $27.9 million and $133.0 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $349.9 million for 2008. This decrease was primarily due to a significant decrease in commodity prices as well as a decline in plant inlet volumes and NGL production. The decline in inlet volumes and NGL production was primarily due to lower throughput on our Bazor Ridge and Alabama Processing systems resulting from reductions in drilling activity and demand as a result of the low commodity price environment, partially offset by an increase in natural gas throughput volumes on our Quivira system. Set forth below is a comparison of the volumetric and pricing data for the 2009 Successor Period, the 2009 Predecessor Period and the year ended December 31, 2008.


	•	Total natural gas throughput volumes on our Gathering and Processing segment were 169.7 MMcf/d and 211.8 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 179.2 MMcf/d in 2008. Natural gas inlet volumes at our owned processing plants were 11.4 MMcf/d and 11.7 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 12.5 MMcf/d in 2008. Gross NGL production volumes at our owned processing plants were 38.2 Mgal/d and 39.3 Mgal/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 40.2 Mgal/d in 2008.

	•	The average realized price of natural gas was $4.71/MMcf and $3.76/MMcf for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $9.08/MMcf in 2008. The average realized price of NGLs was $1.05/gal and $0.70/gal for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $1.36/gal in 2008.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate were $24.2 million and $112.9 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $322.5 million for 2008. This decrease in purchases of natural gas, NGLs and condensate was primarily driven by lower processing volumes as well as lower realized natural gas, NGL and condensate prices.

Segment Gross Margin. Segment gross margin was $3.7 million and $20.0 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $27.4 million for 2008. This decrease was mainly due to lower realized NGL and natural gas prices on our Gloria and Bazor Ridge systems, partially offset by increased throughput volumes on the Lafitte and Quivira systems due to an increase in drilling activity during the high commodity price environment in 2008. Segment gross margin for the Gathering and Processing segment represented 59.3% and 67.0% of our gross margin for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 63.4% for 2008.

Transmission Segment

Revenue. Segment revenue was $5.0 million and $10.2 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $16.5 million for 2008. Total natural gas throughput on our Transmission system was 381.3 MMcf/d and 357.6 MMcf/d in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 336.2 MMcf/d in 2008. Despite the increase in throughput, our segment revenue declined due to a reduction in firm and interruptible transportation revenue across the

segment, specifically caused by the full-year impact of the change in the terms of a contract on our Midla system to more accurately reflect market rates between our Predecessor and an affiliate of our Predecessor.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate were $2.4 million and $0.3 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $0.7 million for 2008. As part of our fixed-margin arrangements, we purchase natural gas, but not NGLs or condensate, in our Transmission segment. This increase was primarily driven by a new fixed-margin arrangement.

Segment Gross Margin. Segment gross margin was $2.5 million and $9.9 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $15.8 million for 2008. The decrease was primarily a result of the full-year impact of the change in the terms of a contract on our Midla system to more accurately reflect market rates between our Predecessor and an affiliate of our Predecessor. This decrease was partially offset by an increase in transportation volumes due to weather-related demand in markets served by the AlaTenn and Midla systems. Segment gross margin for the Transmission segment represented 40.7% and 33.0% of our gross margin for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to 36.6% for 2008.

Direct Operating Expenses. Direct operating expenses were $0.6 million and $3.2 million for the 2009 Successor Period and the 2009 Predecessor Period, respectively, compared to $5.2 million for 2008. This reduction in direct operating expenses was primarily due to the timing of expenditures in connection with a multi-year integrity management program undertaken by our Predecessor.

Liquidity and Capital Resources

Since the acquisition of our assets in November 2009, our sources of liquidity have included cash generated from operations, equity investments by AIM Midstream Holdings and our general partner and borrowings under our credit facility.

Following the closing of this offering, we expect our sources of liquidity to include:


	•	cash generated from operations;

	•	borrowings under our new credit facility; and

	•	issuances of debt and equity securities.

We believe that the cash generated from these sources will be sufficient to allow us to distribute (i) the minimum quarterly distribution on all of our outstanding common and subordinated units and (ii) the corresponding distribution on our 2.0% general partner interest and meet our requirements for working capital and capital expenditures for the foreseeable future.

Working Capital

Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital was ($8.4) million at March 31, 2011, compared to ($4.5) million at December 31, 2010, ($2.4) million at December 31, 2009, $28.6 million at October 31, 2009 and ($3.1) million at December 31, 2008.

The $3.9 million decrease in working capital from December 31, 2010 to March 31, 2011 was primarily a result of the following factors:


	•	an increase in risk management liabilities of $3.1 million during the quarter ended March 31, 2011, offset in part by $0.2 million in risk management assets related to our commodity derivatives; and

	•	an increase of $1.0 million in the current portion of long-term debt associated with the term portion of our credit facility.

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The $2.1 million decrease in working capital from December 31, 2009 to December 31, 2010 was primarily a result of the following factors:


	•	an increase in the current portion of long-term debt associated with an increased amortization payment of $6.0 million due during 2011 compared to $5.0 million due during 2010; and

	•	an increase in accrued expenses and other liabilities of approximately $0.4 million, which was primarily the result of accrued bonus payments and unfavorable contract obligations acquired in connection with our acquisition of our assets.

The $31.7 million net decrease in working capital from December 31, 2008 to October 31, 2009 was primarily the result of the elimination of affiliate obligations in connection with our acquisition of our assets in 2009.

Cash Flows

The following table reflects cash flows for the applicable periods:


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

Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010

Operating Activities. Net cash provided by (used in) operating activities was $5.1 million for the quarter ended March 31, 2011 compared to $2.3 million for the quarter ended March 31, 2010. The change in cash provided by (used in) operating activities was primarily a result of the combined effects of a net loss, net of non-cash changes, in addition to net positive changes in operating assets and liabilities.

Investing Activities. Net cash provided by (used in) investing activities was ($1.3) million for the quarter ended March 31, 2011 compared to ($0.5) million for the quarter ended March 31, 2010. The change in cash provided by (used in) investing activities was primarily a result of an increase in maintenance capital expenditures associated with our Bazor Ridge and certain of our other, smaller systems.

Financing Activities. Net cash provided by (used in) financing activities was ($3.7) million for the quarter ended March 31, 2011 compared to $2.9 million for the quarter ended March 31, 2010. The change in cash provided by (used in) financing activities was primarily a result of unitholder distributions, offset in part by borrowings under our credit facility.

Year Ended December 31, 2010 Compared to the 2009 Successor Period and the 2009 Predecessor Period

Operating Activities. Net cash provided by (used in) operating activities was $13.8 million for the year ended December 31, 2010 compared to ($6.5) million and $14.6 million for the 2009 Successor Period and 2009 Predecessor Period, respectively. The change in cash provided by (used in) operating activities was primarily a result of the combined effects of a net loss, net of non-cash charges, in addition to net positive changes in operating assets and liabilities.

Investing Activities. Net cash provided by (used in) investing activities was ($10.3) million for the year ended December 31, 2010 compared to ($152.0) million and ($0.9) million for the 2009 Successor Period and 2009 Predecessor Period, respectively. The change in cash used in investing activities was primarily a result of

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our acquisition of our assets in November 2009 for cash consideration of $150.8 million and the construction of the Winchester lateral in November 2010.

Financing Activities. Net cash provided by (used in) financing activities was ($4.6) million for the year ended December 31, 2010 compared to $159.7 million and ($14.0) million for the 2009 Successor Period and 2009 Predecessor Period, respectively. The change in cash provided by (used in) financing activities was primarily a result of net borrowings under our credit facility of $61.0 million and a capital contribution of $100.0 million by AIM Midstream Holdings in connection with our acquisition of our assets and funding our initial working capital requirements in November 2009. During the year ended December 31, 2010, AIM Midstream Holdings contributed an additional $12.0 million to us, we made approximately $5.0 million of amortization payments under the term loan portion of our existing credit facility and we made distributions of $11.8 million to our unitholders.

The 2009 Successor Period and the 2009 Predecessor Period Compared to Year Ended December 31, 2008

Operating Activities. Net cash provided by (used in) operating activities was ($6.5) million and $14.6 million for the 2009 Successor Period and 2009 Predecessor Period, respectively, compared to $18.2 million for the year ended December 31, 2008. The change in cash provided by (used in) operating activities was primarily a result of the combined effects of a net loss, net of non-cash charges, in addition to net negative changes in operating assets and liabilities.

Investing Activities. Net cash provided by (used in) investing activities was ($152.0) million and ($0.9) million for the 2009 Successor Period and 2009 Predecessor Period, respectively, compared to ($10.5) million for the year ended December 31, 2008. The change in cash used in investing activities was primarily a result of our acquisition of our assets in November 2009 for cash consideration of $150.8 million.

Financing Activities. Net cash provided by (used in) financing activities was $159.7 million and ($14.0) million for the 2009 Successor Period and 2009 Predecessor Period, respectively, compared to ($7.9) million for the year ended December 31, 2008. The change in net cash provided by (used in) financing activities was primarily a result of net borrowings under our credit facility of $61.0 million and a capital contribution of $100.0 million by AIM Midstream Holdings in connection with our acquisition of our assets and funding our initial working capital requirements in November 2009.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Capital Requirements

The midstream energy business can be capital intensive, requiring significant investment for the maintenance of existing assets or acquisition or development of new systems and facilities. We categorize our capital expenditures as either:


	•	maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or

	•	expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in the regions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. For the year ended December 31, 2010, our capital expenditures totaled $10.3 million. For this period, capital expenditures included maintenance capital expenditures and expansion capital expenditures. We estimate that 16.2% of our capital expenditures, or $1.7 million, were maintenance capital expenditures and that 83.8% of our capital

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expenditures, or $8.6 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 through a capital contribution made to us by AIM Midstream Holdings and our general partner.

We have budgeted $3.2 million in capital expenditures for the year ending December 31, 2011, of which $0.2 million represents expansion capital expenditures and $3.0 million represents maintenance capital expenditures. At December 31, 2010, we had no budgeted expansion capital expenditures for 2011. However, in February 2011, our general partner’s board of directors approved a $0.2 million upgrade on our existing Gloria compressor that we expect to increase throughput capacity on the Gloria system and be completed in 2011.

Our 2010 expansion capital expenditures were $8.6 million and our maintenance capital expenditures were $1.7 million. Our expansion capital expenditures during 2010 included:


	•	the construction of the Winchester lateral on our Bazor Ridge system for $3.9 million, effectively upgrading the system and increasing the effective operating capacity of that system;

	•	the construction of a strategic interconnect between our Lafitte system and TGP for $1.4 million, which allows us to move gas from TGP onto our Lafitte and Gloria systems for processing and delivery to customers downstream;

	•	the movement and recommissioning of the Atmore processing facility to serve a producer customer for $0.8 million; and

	•	$2.5 million of expansion capital expenditures comprised of approximately 25 small capital projects.

In addition to our budgeted capital projects, we intend to use a portion of the net proceeds from this offering to establish a cash reserve of $2.2 million related to non-recurring deferred maintenance capital expenditures for the twelve months ending June 30, 2012.

We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under our new credit facility and the issuance of debt and equity securities.

Integrity Management

When we acquired our operating assets from Enbridge, we inherited an ongoing integrity management program required under regulations of the U.S. Department of Transportation, or DOT. These regulations require transportation pipeline operators to implement continuous integrity management programs over a seven-year cycle. Our current program will be completed in 2012. In connection with the acquisition of our assets from Enbridge we initiated a comprehensive review of the program and concluded that there were sixteen high consequence areas, or HCAs, in addition to those identified by our Predecessor that required further testing pursuant to DOT regulations. We expect to incur $2.1 million in integrity management expenses in 2012 associated with these HCAs to complete the current integrity management program.

Beginning in 2013 we will begin a new integrity management program during which we expect to incur an average of $1.5 million in integrity management expenses per year over the course of the seven-year cycle.

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Because DOT regulations require integrity management activities for each HCA to be performed within seven years from when they were last performed, we expect to incur the following expenses:


Year	Integrity Management Expense
	(in thousands)

2013	$	2,000
2014		5,015
2015		839
2016		675
2017		0
2018		0
2019		2,080

Total	$	10,609

In conjunction with the commencement of our next seven-year integrity management program cycle in 2013, we plan to request the DOT’s consent to a modification of the timing of our integrity management expenses so that we spend approximately $1.5 million each year.

Impact of Bazor Ridge Emissions Matter

With respect to our Bazor Ridge processing plant, we recently determined that (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 in 2009 and 2010 that was not made. Please read “Business — Environmental Matters — Air Emissions” for more information about these matters.

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.

While we cannot currently estimate the amount or timing of any sanctions we might be required to pay, permits we might be required to obtain, or operational restrictions, limitations or capital expenditures that we might be required to make, we expect to use proceeds from additional borrowings under our new credit facility to pay any such sanctions or fund any such operational restrictions or limitations or capital expenditures. We do not believe that any such borrowings would have a material impact on our cash available for distribution during the twelve months ending June 30, 2012.

Distributions

We intend to pay a quarterly distribution at an initial rate of $0.4125 per unit, which equates to an aggregate 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 do not have a legal obligation to make distributions except as provided in our partnership agreement.

Our Credit Facility

On November 4, 2009, we entered into our current $85.0 million secured credit facility with a syndicate of lending institutions. The credit facility is composed of a $50.0 million term loan facility and a $35.0 million revolving credit facility, which includes a sub-limit of up to $5.0 million for same-day swing line advances and a sub-limit of up to $10.0 million for letters of credit. Borrowings under our revolving or term loan facility bear interest at a variable rate per annum equal to the Base Rate or Eurodollar-based Rate, as the case may be, plus the Applicable Margin. Base Rate, Eurodollar-based Rate, Applicable Margin, Total

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Debt, and Consolidated EBITDA are each defined in the credit agreement that evidences our current facility. Our obligations under our current credit facility are secured by a lien on and a security interest in all of our personal property and our real property with an aggregate value equal to at least eighty percent (80%) of the total value of all of our real property. The terms of our credit facility contain customary covenants, including those that restrict our ability to make certain payments, distributions, acquisitions, loans, or investments, incur certain indebtednesses or create certain liens on our assets, consolidate or enter into mergers, dispose of certain of our assets, engage in certain types of transactions with our affiliates, enter into certain sale/leaseback transactions and modify certain material agreements. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date in November 2012. As of December 31, 2010, we were in compliance with the covenants in our credit facility.

The events that constitute default under our current credit facility include, among other things, the failure to pay principal and interest on the indebtedness under our current facility when due, failure to comply with certain covenants or breach representations and warranties made under our current credit facility, certain bankruptcy, dissolution, liquidation or other insolvency events, or a change of control. In addition, our current certain facility includes cross default provisions with respect to indebtedness for borrowed money (other than is borrowed under our current facility) that is in excess of $1.0 million, individually, or in the aggregate.

In connection with our initial public offering, we plan to pay off our existing credit facility and enter into a new $100.0 million revolving credit facility. The new credit facility will mature in 2016, and borrowings will bear interest, at a variable rate per annum equal to, at our option, LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin will each be defined in the credit agreement that evidences our new credit facility). Under our new credit facility, in addition to the uses described in “Use of Proceeds,” we expect that borrowings may be used for (i) the refinancing and repayment of certain existing indebtedness, (ii) working capital and other general partnership purposes and (iii) future capital expenditures. Borrowings under our new credit facility will be secured by a first-priority lien on and security interest in substantially all of our assets. We expect the credit agreement that evidences our new credit facility to contain customary covenants, including restrictions on our ability to incur additional indebtedness, make certain investments, loans or advances, make distributions to our unitholders, make dispositions or enter into sales and leasebacks, or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries. The credit agreement will also require compliance with certain financial covenant ratios, including limiting our total leverage ratio (ratio of consolidated indebtedness to consolidated EBITDA) to no greater than 4.5x (or under certain circumstances, 5.0x) and limiting our interest coverage ratio (ratio of consolidated EBITDA to consolidated interest expense) to no less than 2.5x.

The events that constitute an Event of Default under our new credit agreement are expected to be customary for loans of this size and type.

Credit Risk

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. and Dow Hydrocarbons and Resources and accounted for approximately 34%, 29% and 10%, respectively, of our segment revenue for the year ended December 31, 2010. 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. We examine the creditworthiness of third-party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

Customer Concentration

A significant percentage of the gross margin in each of our segments is attributable to a relatively small number of customers. 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

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ended December 31, 2010 and 15% and 23%, respectively, for the quarter ended March 31, 2011. In our Transmission segment, Calpine Corporation accounted for approximately 38% and 30% of our segment gross margin for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. Although we have gathering, processing or transmission contracts with each of these customers of varying duration, 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.

Contractual Obligations

The table below summarizes our contractual obligations and other commitments as of December 31, 2010:


			Less Than		1-3				More Than
Contractual Obligation	Total		1 Year		Years		3-5 Years		5 Years
					(in thousands)

Long-term debt(1)	$	56,370	$	6,000	$	50,370	$	—	$	—
Rights-of-way and operating leases		2,057		580		747		700		30
Asset retirement obligations		8,340		914		—		—		7,426

Total	$	66,767	$	7,494	$	51,117	$	700	$	7,456

(1)

Upon the closing of this offering, we expect to incur long-term debt under our new credit facility of $100.0 million, which will be used, together with the net proceeds of this offering, to make a distribution to AIM Midstream Holdings, the LTIP participants holding common units and our general partner as described in “Use of Proceeds.” We expect the initial interest rate under our new credit facility to be 3.0%.

Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate in our Gathering and Processing segment. Both our profitability and our cash flow are affected by volatility in the prices of these commodities. Natural gas and NGL prices are impacted by changes in the supply and demand for natural gas and NGLs, as well as market uncertainty. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors.” Adverse effects on our cash flow from reductions in natural gas and NGL product prices could adversely affect our ability to make distributions to unitholders. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, optimization of our assets, and the use of derivative contracts. Our overall direct exposure to movements in natural gas prices is minimal as a result of natural hedges inherent in our current contract portfolio. Natural gas prices, however, can also affect our profitability indirectly by influencing the level of drilling activity in our areas of operation. We are a net seller of NGLs, and as such our financial results are exposed to fluctuations in NGLs pricing. In January 2011, we implemented a hedging program by entering into a number of financial hedges to protect our expected NGL production through mid 2012. Through these January 2011 hedge transactions, we executed swap and put contracts settled against the market prices of ethane, propane, iso-butane, normal butane and natural gasoline.

We continually and proactively monitor our commodity exposure and compare this exposure to our stated hedging strategy. In June 2011, the Board of Directors of our general partner determined that we would gain operational and strategic flexibility from cancelling our then-existing swap contracts and entering into a new swap contract with an existing counterparty that extends through the end of 2012. We did not modify the put contracts we entered into through our January 2011 hedge transactions.

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Pursuant to our January 2011 hedge transactions and June 2011 hedge transactions, we have hedged approximately 85% of our expected exposure to NGL prices in 2011, and approximately 79% in 2012.

In June 2010, prior to our entry into our January 2011 hedge transactions, we executed a series of put contracts settled against a basket of NGLs. Under these put contracts, we receive a fixed floor price of $1.03 per gallon on 13,212 gal/d of a negotiated NGL and liquids basket, which included ethane, propane, iso-butane, normal butane, natural gasoline and WTI crude oil. The relative weightings of the price of each component of the basket are calculated via an arithmetic formula. Based on the current commodity price environment, these hedges are currently out of the money.

The table below sets forth certain information regarding our NGL fixed swaps as of December 31, 2010 and June 27, 2011:


		Notional		Weighted Average Price			Fair Market Value
		Volumes		($/gal)			December 31,		June 27,
Commodity	Period	(gal/d)		We Receive		We Pay	2010		2011

Ethane	Jul 2011-Dec 2012		7,300	$	0.57	OPIS avg		N/A	$	(177,059	)
Propane	Jul 2011-Dec 2012		7,050	$	1.40	OPIS avg		N/A	$	44,429
Iso-Butane	Jul 2011-Dec 2012		2,510	$	1.81	OPIS avg		N/A	$	80,532
Normal Butane	Jul 2011-Dec 2012		3,000	$	1.74	OPIS avg		N/A	$	93,401
Natural Gasoline	Jul 2011-Dec 2012		5,500	$	2.31	OPIS avg		N/A	$	318,477

Total			25,360	$	1.44			N/A	$	359,600

The table below sets forth certain information regarding our NGL puts as of December 31, 2010 and June 27, 2011:


		Notional		Floor Strike		Fair Market Value
		Volumes		Price		December 31,		June 27,
Commodity	Period	(gal/d)		($/gal)		2010		2011

NGL basket(1)	Feb 2011-Jul 2012		9,800	$	1.29		N/A	$	185,849
NGL basket(2)	Jul 2010-Jun 2011		13,212	$	1.03	$	—	$	0

Total			23,012	$	1.14	$	—	$	185,849


(1)		In January 2011, we entered into a put arrangement under which we receive a fixed floor price of $1.29 per gallon on 9,800 gal/d of a negotiated NGL basket, which includes ethane, propane, iso-butane, normal butane and natural gasoline. The relative weightings of the price of each component of the basket are calculated via an arithmetic formula.

(2)		In June 2010, we entered into a put arrangement under which we receive a fixed floor price of $1.03 per gallon on 13,212 gal/d of a negotiated NGL and liquids basket, which includes ethane, propane, iso-butane, normal butane, natural gasoline and WTI crude oil. The relative weightings of the price of each component of the basket are calculated via an arithmetic formula.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our credit facility. In December 2009, we entered into an interest rate cap with participating lenders with a $26.5 million notional amount at December 31, 2010 that effectively caps our Eurodollar-based rate exposure on that portion of our debt at a maximum of 4.0%. We anticipate that, in conjunction with our entry into a new credit facility contemporaneous with the closing of this offering, we would implement similar swap or cap structures to mitigate our exposure to interest rate risk.

The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will continue to tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

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A hypothetical increase or decrease in interest rates by 1.0% would have changed our interest expense by $0.6 million for the year ended December 31, 2010.

Impact of Seasonality

Results of operations in our Transmission segment are directly affected by seasonality due to higher demand for natural gas during the winter months, primarily driven by our LDC customers. On our AlaTenn system, we offer some customers seasonally-adjusted firm transportation rates that require customers to reserve capacity at rates that are higher in the period from October to March compared to other times of the year. On our Midla system, we offer customers seasonally-adjusted firm transportation reservation volumes that allow customers to reserve more capacity during the period from October to March compared to other times of the year. The combination of seasonally-adjusted rates and reservation volumes, as well as higher volumes overall, result in higher revenue and segment gross margin in our Transmission segment during the period from October to March compared to other times of the year. We generally do not experience seasonality in our Gathering and Processing segment.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires our and our Predecessor’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by our and Predecessor’s management to be critical to an understanding of the financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

Use of Estimates. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect our reported financial positions and results of operations. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenue and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing tangible and intangible assets for possible impairment, (4) estimating the useful lives of our assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from our estimates.

Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment is depreciated using the straight-line method over the estimated useful lives of the assets. The costs of renewals and betterments which extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects are expensed as incurred.

Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.

Impairment of Long-Lived Assets. We assess our long-lived assets for impairment on authoritative guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its

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carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

Examples of long-lived asset impairment indicators include:


	•	a significant decrease in the market price of a long-lived asset or asset group;

	•	a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;

	•	a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;

	•	as accumulation of costs significantly in excess of the amount originally expected for the for the acquisition or construction of the long-lived asset or asset group;

	•	a current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and

	•	a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

We incurred no impairment charges during the year ended December 31, 2010.

Environmental Remediation. Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. As of December 31, 2010 we have recorded no liability for remediation expenditures. If governmental regulations change, we could be required to incur remediation costs which may have a material impact on our profitability.

Asset Retirement Obligations. As of December 31, 2010, we have recorded liabilities of $7.2 million for future asset retirement obligations associated with our pipeline assets. Related accretion expense has been recorded in interest expense as discussed in Note 1 in our consolidated financial statements. The recognition of an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as costs of remediation, timing of settlement to changes in the estimate of the costs of remediation. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset or corresponding liability on a prospective basis and an adjustment in our depreciation expense in future periods.

Equity-Based Awards. We account for equity-based awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Equity-based compensation expense is recorded based upon the fair value of the award at grant date. Such costs are recognized as expense on a straight-line basis over the corresponding vesting period.

During 2010 and 2009, the fair values of the phantom-unit grants that we made were calculated based on several valuation models, including a discounted cash flow, or DCF, model, a comparable company multiple analysis and a comparable transaction multiple analysis. The DCF model included certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. Both the comparable company analysis and comparable transaction analysis contain significant assumptions consistent with the DCF model, in addition to assumptions related to comparability, appropriateness of multiples (primarily based on EBITDA and distributable cash flow) and certain assumptions in the calculation of enterprise value. The initial valuation of $10.00 per common unit was prepared in August 2009 in connection with our formation in anticipation of the acquisition of our assets from a subsidiary of Enbridge Energy Partners, L.P. In November 2009, we received indirect third-party investments at that same valuation in connection with the acquisition of our assets from Enbridge. We assessed the adequacy of that valuation on each grant date subsequent to the initial fair value calculation to determine if

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events or circumstances had occurred that would cause that valuation to become less relevant, noting none. Moreover, we received additional indirect third-party investments at $10.00 per common unit in each of September and November 2010. As a result, we maintained that $10.00 valuation for phantom-unit grants made in November 2009, March 2010 and October 2010.

For the phantom-unit grants made during March 2011, the fair values of the grants were calculated by affiliates of our general partner as $13.67 per common unit based on several valuation models as of December 31, 2010, including a DCF model, a comparable company multiple analysis and a comparable transaction multiple analysis. The DCF model includes certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. Both the comparable company analysis and comparable transaction analysis contain significant assumptions consistent with the DCF model, in addition to assumptions related to comparability, appropriateness of multiples (primarily based on EBITDA and distributable cash flow) and certain assumptions in the calculation of enterprise value. The year-end 2010 valuation was completed in January 2011. We assessed the adequacy of that valuation in connection with the March 2011 grant date to determine if events or circumstances had occurred since December 31, 2010 that would cause that valuation to become less relevant, noting none.

As adjusted to reflect the reverse stock split described under the caption “Summary — Recapitalization Transactions and Partnership Structure,” the $13.67 fair value per phantom unit is $28.17 per phantom unit as compared to an assumed offering price of $20.00 per common unit. The difference in the post-split $28.17 per phantom unit and the assumed offering price of $20.00 per common unit is primarily attributable to the dilutive effect of the issuance of common units in this offering.

Revenue Recognition. We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. We record revenue and cost of product sold on the gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that is purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation we record those fees separately in revenue. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer.

Natural Gas Imbalance Accounting. Quantities of natural gas over-delivered or under-delivered related to operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices at the time the imbalance was created. Monthly, gas imbalances over-delivered are valued at the lower of cost or market; gas imbalances under-delivered are valued at replacement cost. These imbalances are typically settled in the following month with deliveries of natural gas. Under the contracts, imbalance cash-outs are recorded as a sale or purchase of natural gas, as appropriate.

Price Risk Management Activities. We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks and to help maintain compliance with certain financial covenants in our credit facility. These hedging activities rely upon forecasts of our expected operations and financial structure through December 2012. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed.

From the inception of our hedging program in December 2009, we used mark-to-market accounting for our commodity hedges and interest rate caps. We record monthly realized gains and losses on hedge instruments based upon cash settlements information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses quarterly based upon the future value on mark-to-market hedges through their expiration dates. The expiration dates vary but are currently no later than October 2012 for our interest rate hedge and December 2012 for our commodity hedges. Costs incurred to purchase interest rate and NGL puts are amortized during the contract period through the unrealized risk management instruments in total revenue. We monitor and review hedging positions regularly.

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INDUSTRY OVERVIEW

General

The midstream natural gas industry provides the link between the exploration and production of raw natural gas and the delivery of that natural gas and its by-products to industrial, commercial and residential end users. The principal components of the business consist of gathering, compressing, treating, dehydrating, processing, fractionating, transporting and marketing natural gas and natural gas liquids, or NGLs. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing and treating plants to natural gas producing wells. Companies within this industry provide services at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and NGLs, and then routing the separated dry gas and NGL streams to the next intermediate stage of the value chain or to transportation pipelines for delivery to end-markets. Transportation consists of moving pipeline-quality natural gas from these gathering systems and plants for delivery to customers.

The following diagram illustrates the various components of the natural gas value chain:

Midstream Services

The range of services provided by midstream natural gas service providers are generally divided into the following six categories:

Gathering. At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport natural gas from the wellhead to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression. Gathering systems are operated at design pressures that maximize the total throughput from all connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time near the wellhead to maintain throughput across the gathering system.

Treating and Dehydration. Another process in the midstream value chain is treating and dehydration, a step that involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. Moreover, end users will not purchase natural gas with a high level of these impurities. To meet downstream pipeline and end-user natural gas quality standards, the natural gas is

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dehydrated to remove the saturated water and is chemically treated to separate the impurities from the gas stream.

Processing. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, most natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs. This natural gas, referred to as rich or wet natural gas, must be processed to remove these heavier hydrocarbon components, as well as natural gas condensate. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation. The mixture of NGLs that results from natural gas processing is generally comprised of the following five components: ethane, propane, normal butane, iso-butane and natural gasoline. This mixture is often referred to as y-grade or raw make NGL. Fractionation is the process by which this mixture is separated into the NGL components prior to their sale to various petrochemical and industrial end users.

Transmission. Once the raw natural gas has been treated and processed, the remaining natural gas, or residue natural gas, and NGL components are transported and marketed to end users. The transmission of natural gas involves the movement of pipeline-quality natural gas from gathering systems and processing facilities to wholesalers and end users, including industrial plants and LDCs. LDCs purchase natural gas from transmission companies and market that natural gas to commercial, industrial and residential end users. Transmission pipelines generally span considerable distances and consist of large-diameter pipelines that operate at higher pressures than gathering pipelines to facilitate the transportation of greater quantities of natural gas. The concentration of natural gas production in a few regions of the U.S. generally requires transmission pipelines to cross state borders to meet national demand. These pipelines are referred to as interstate pipelines and are primarily regulated by federal agencies or commissions, including the FERC. Pipelines that transport natural gas produced and consumed wholly within one state are generally referred to as intrastate pipelines. Intrastate pipelines are primarily regulated by state agencies or commissions.

Typical Midstream Contractual Arrangements

The midstream services described above, with the exception of transmission, are typically provided under contracts that vary in the amount of commodity price risk they carry. The following four contractual arrangements are the most common in the midstream industry:


	•	*Fee-Based.* In exchange for its gathering, compression and treating services, the midstream service provider receives a fee per unit of natural gas that is gathered at the wellhead, compressed and treated. Depending on the fee structure, producer customers may pay a single bundled fee for gathering, treating and compressing, or those services may be unbundled. Under fee-based arrangements, the midstream service provider bears no direct commodity price risk, although a sustained decline in natural gas prices may result in a decline in volumes of natural gas for which these services are needed.

	•	*Fixed-Margin.* Under these arrangements, the midstream service provider purchases natural gas from producers or suppliers at receipt points on its systems at an index price less a fixed transportation fee and simultaneously sells an identical volume of natural gas at delivery points on its systems at the same, undiscounted index price. By entering into back-to-back purchases and sales of natural gas, the midstream service provider is able to lock in a fixed-margin on these transactions. These contracts are sometimes referred to as wellhead purchase agreements.

	•	*Percent-of-Proceeds, or POP.* In exchange for its processing services, the midstream service provider remits to a producer customer a percentage of the proceeds from sales of residue natural gas and/or NGLs that result from its processing, or in some cases, a percentage of the physical residue natural gas

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		and/or NGLs at the tailgate of the processing plant, retaining the balance of the proceeds or physical commodity for its own account. These types of arrangements expose the midstream service provider to direct commodity price risk because the revenue from these contracts directly correlates with the fluctuating price of natural gas and/or NGLs. Moreover, the midstream service provider using a percent-of-proceeds arrangement will bear indirect commodity price risk in that a sustained decline in natural gas or NGL prices may result in a decline in volumes of natural gas for which processing services are needed.


	•	*Keep-Whole.* Keep-whole arrangements may be used for processing services. Under these arrangements, the midstream service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the natural gas, is returned to the producer customer. Since some of the natural gas is used and removed during processing, the midstream service provider compensates the producer customer for the amount used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have the highest direct commodity price exposure for the midstream service provider because its costs are dependent on the price of natural gas and its revenue is based on the price of NGLs, each of which fluctuate independently.

There are three primary forms of contracts utilized in the transmission of natural gas, firm transportation contracts and interruptible transportation contracts.


	•	*Firm Transportation.* Firm transportation contracts require a shipper customer to pay a monthly reservation charge, which is a fixed charge owed regardless of the actual pipeline capacity used by that customer. When a shipper customer uses the capacity it has reserved under these contracts, the midstream service provider also collects a usage charge based on the volume of natural gas actually transported. Usage charges generally enable the midstream service provider to recover the variable costs of operating the transmission system. Usage charges are typically a small percentage of the total revenue received under firm transportation contracts.

	•	*Interruptible Transportation.* Interruptible transportation contracts require a shipper customer to pay fees based on its actual use of the transmission system and related services. Shipper customers with interruptible transportation contracts are not assured capacity or service on the transmission pipeline. To the extent that the transmission pipeline has physical capacity resulting from firm transportation contracts that are not being fully utilized, the system uses that capacity for interruptible service.

	•	*Fixed-Margin Transportation.* Under these arrangements, the midstream service provider purchases natural gas from producers or suppliers at receipt points on its systems at an index price less a fixed transportation fee and simultaneously sells an identical volume of natural gas at delivery points on its systems at the same, undiscounted index price. These contracts are sometimes referred to as wellhead purchase agreements.

U.S. Natural Gas Fundamentals

Natural gas is a critical component of energy consumption in the United States. According to the EIA, annual consumption of natural gas in the United States increased from approximately 22.8 Tcf in 2009 to approximately 24.1 Tcf in 2010, an increase of approximately 5.7%. Total annual domestic natural gas consumption is expected to rise from 24.1 Tcf in 2010 to 26.5 Tcf in 2035.

In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset the decline rates of existing production. Over the past several years, a fundamental shift in U.S. natural gas production has emerged with the contribution of natural gas from unconventional resources, defined by the EIA as natural gas produced from shale formations and coalbeds. The primary factors driving this shift are the emergence of unconventional natural gas plays and advances in technology that have allowed producers to cost-effectively extract significant volumes of natural gas from these plays. The development of these unconventional sources

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offsets declines in other U.S. natural gas supply, meeting growing consumption and lowering the need for imported natural gas.

According to the EIA:


	•	The industrial and electricity generation sectors are the largest users of natural gas in the United States, accounting for approximately 58% of the total natural gas consumed in the United States during 2010;

	•	Annual industrial natural gas demand is expected to grow sharply in the near term, from 7.3 Tcf in 2009 to 9.4 Tcf in 2020 as a result of an expected recovery in industrial production;

	•	In 2010, the end-user commercial and residential sectors accounted for approximately 34% of the total natural gas consumed in the United States; and

	•	During the last five years ending December 31, 2010, the United States has on average consumed approximately 23.0 Tcf per year, with average annual domestic production of approximately 20.0 Tcf during the same period.

The graph below represents projected U.S. natural gas production versus U.S. natural gas consumption through the year 2035.

Source: Energy Information Administration.

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BUSINESS

Overview

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 under our elective processing arrangements, we typically retain and sell a percentage of the residue natural gas and resulting NGLs under POP arrangements. We own three processing facilities that produced an average of approximately 34.1 Mgal/d and 55.1 Mgal/d of gross NGLs for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. In addition, in connection with our elective processing arrangements, we contract for processing capacity at a third-party plant where we have the option to process natural gas that we purchase. Under these arrangements, we sold an average of approximately 28.1 Mgal/d and 35.0 Mgal/d of net equity NGL volumes for the year ended

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December 31, 2010 and the quarter ended March 31, 2011, respectively. 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, was segment gross margin generated in our Gathering and Processing segment and $13.5 million and $4.1 million, respectively, was 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 and $7.3 million, or 65.4% and 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


	•	*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. We expect to have opportunities to expand our systems into new markets and sources of supply, which we believe will make our services more attractive to our customers. We intend to focus on projects that can be completed at a relatively low cost and have potential for attractive returns. 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.


	•	*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 aggressively marketing our services to additional customers in our areas of operation. In addition, we intend to rebuild or reestablish relationships with customers that were potentially underserved by the previous owner of our assets. For example, in 2010 we were able to contract with a customer on our Gloria system for volumes of natural gas that it had decided to have gathered and processed by alternative means prior to our acquisition of the system. We have available capacity on a majority of our systems, and as a result, we can accommodate additional volumes at a minimal incremental cost.

	•	*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 returns in new operating regions or business lines. We will pursue acquisitions in our areas of operation that we believe will allow us to realize operational efficiencies by capitalizing on our existing infrastructure, personnel and customer relationships. We will also seek acquisitions in new geographic areas or new

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		but related business lines to the extent that we believe we can utilize our operational expertise to enhance our business with these acquisitions.


	•	*Manage Exposure to Commodity Price Risk.* We will manage our commodity price exposure by targeting a contract portfolio that is weighted towards firm transportation, fee-based and fixed-margin contracts while mitigating direct commodity price exposure by employing a prudent hedging strategy. For the year ended December 31, 2010 and the quarter ended March 31, 2011, approximately 65.4% and 59.5%, respectively, of our gross margin was generated from firm transportation, fee-based and fixed-margin contracts that, together with our percent-of-proceeds contracts and hedging activities, generated relatively stable cash flows. For the years ending December 31, 2011 and 2012, we have hedged 85% and 79%, respectively, of our expected net equity NGL volumes with a combination of swaps and puts for the specific NGL components to which we are exposed. With respect to our exposure to natural gas prices, we are currently long natural gas on certain of our systems and short natural gas on certain of our other systems, which effectively creates a natural hedge against our exposure to fluctuations in the price of natural gas.

	•	*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 challenging commodity price or capital markets environments. At the closing of this offering, we anticipate entering into a new credit facility with sufficient capacity to fund acquisitions, expansions and working capital for our operations.

	•	*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. To this end, we implemented a safety performance program, including an integrity management program, upon our formation in 2009 and implemented planned maintenance programs to increase the safety, reliability and efficiency 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, positions us to pursue economically attractive growth projects and acquisitions that may not be large enough to be attractive to many of our larger competitors. Given the current size of our business, these opportunities may have a larger impact on us than they would have on our competitors and may provide us with material growth opportunities. In addition, as a result of our focus on customer service, we believe that we have unique insights into our customers’ needs and are well situated to take advantage of organic growth opportunities that arise from those needs. For example, in 2010 we identified and executed an opportunity to construct a major interconnection on our Lafitte system with a third-party interstate pipeline offshore Louisiana that provides additional volumes to a customer’s refinery while also substantially increasing the utilization of both our Gloria and Lafitte systems.

	•	*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 avenues for our business. We primarily operate in five states, have access to multiple sources of natural gas supply and service various interstate and intrastate pipelines as well as utility, industrial and other commercial customers. We believe this diversification provides us with a variety of growth opportunities and mitigates our exposure to reduced activity in any one area.

	•	*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

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		our assets are strategically positioned to capitalize on the resurgent drilling activity, increased demand for midstream services and growing commodity consumption in the Gulf Coast and Southeast U.S. regions. This belief is based on:


	•	the proximity of our gathering and transmission systems to newly producing wells and the relatively lower cost to connect to our systems compared to those farther away;

	•	the available capacity of our systems, coupled with an ability to add capacity economically to our systems; and

	•	the fact that many of our systems have multiple downstream interconnects that provide our customers with multiple market delivery options, thus causing our systems to be more attractive versus those of our competitors.


	•	*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. Furthermore, we believe our entrepreneurial culture and smaller size relative to our peers enables us to offer more customized and creative solutions for our customers and to be more responsive to their needs. We believe our customer focus will enable us to capture new opportunities and expand into new markets.

	•	*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. In addition, our field supervisory team has operated our assets for an average of over 20 years. We believe that our field employees’ knowledge of the assets will further contribute to our ability to execute our business strategies. Furthermore, the interests of our executive management and operating teams are strongly aligned with those of common unitholders, including through their ownership of common units and our Long-Term Incentive Plan.

Our Sponsor

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.

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Our Assets

We own and operate all of our assets, which consist of nine gathering systems, three processing facilities, two interstate pipelines and six intrastate pipelines. Our assets are primarily located in Alabama, Louisiana, Mississippi, Tennessee and Texas. We organize our operations into two business segments: (i) Gathering and Processing; and (ii) Transmission. The following table provides information regarding our segments and assets as of March 31, 2011 and for the year ended December 31, 2010 and the quarter ended March 31, 2011.


											Approximate
											Average
					Approximate						Throughput (MMcf/d)
					Number				Approximate		Year		Quarter
					of Connected				Design		Ended		Ended
		Contract			Wells/Receipt		Compression		Capacity		December 31,		March 31,
	System Type	Type(1)	Miles		Points		(Horsepower)		(MMcf/d)		2010		2011


Gathering & Processing

Gloria	Gathering,	Fee(5), POP		110		57		1,877		60		36.6		49.0
	Processing(2)

Lafitte	Gathering	Fee(5)		40		44		—		71		12.0		19.9

Bazor Ridge	Gathering,	Fee, POP		160		40		6,287		22		9.2		13.6
	Processing

Quivira	Gathering	Fee		34		16		—		140		77.4		113.5

Offshore Texas	Gathering	Fee(5)		56		22		—		100		15.3		19.2

Other(3)	Gathering,	Fee(5), POP		189		445		5,156		153		25.1		27.6
	Processing


Gathering & Processing total				589		624		13,320		546		175.6		242.8


Transmission

Bamagas	Intrastate	FT		52		2		—		450		151.5		180.9

AlaTenn	Interstate	FT, IT		295		4		3,665		200		48.0		66.2

Midla	Interstate	FT, IT		370		9		3,600		198		87.2		121.6

MLGT	Intrastate	FT, IT(5)		54		7		—		170		50.5		63.8

Other(4)	Intrastate	FT, IT		82		6		—		336		13.0		13.4


Transmission total				853		28		7,265		1,354		350.2		445.9


(1)		In this table, fee refers to fee-based contracts, POP refers to percent-of-proceeds contracts, FT refers to firm transportation contracts and IT refers to interruptible transportation contracts. For a general description of these types of contracts, please see “Industry Overview — Typical Midstream Contractual Arrangements.”

(2)		Although the Gloria system is comprised solely of gathering pipelines, we generate a substantial portion of our Gloria revenue by processing natural gas for our own account at the Toca processing plant in connection with our elective processing arrangements. We do not own the Toca processing plant, but we have the contractual ability to process the natural gas for our own account and retain the majority of the proceeds derived from the sale of the residue natural gas and resulting NGLs. Please see “— Gathering and Processing Segment — Gloria System.”

(3)		Includes our Alabama Processing, Fayette, Magnolia, Stringer and Heidelberg systems.

(4)		Includes our Trigas, Owens Corning and Chalmette systems.

(5)		Because we view the segment gross margin earned under our fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements in our Gathering and Processing segment and the fee earned in our interruptible transportation arrangements in our Transmission segment, we have included the fixed-margin arrangements in those categories.

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Gathering and Processing Segment

General

Our Gathering and Processing segment is an integrated midstream natural gas system that provides the following services to our customers:


	•	gathering;

	•	compression;

	•	treating;

	•	processing;

	•	transportation; and

	•	sales of natural gas, NGLs and condensate.

For a description of these services, please read “Industry Overview — Midstream Services.”

We own one processing plant on our Bazor Ridge system, two on our Alabama Processing system and have the right to contract for processing services for our own account at another, the Toca plant, that is connected to our Gloria system. The Toca plant is owned and operated by Enterprise. Our Bazor Ridge processing plant and the Toca plant are both cryogenic processing plants. These types of processing plants represent the latest generation of processing techniques, using extremely low temperatures and high pressures to optimize the extraction of NGLs from the raw natural gas stream.

We generally derive revenue in our Gathering and Processing segment from fee-based, fixed-margin and POP arrangements, whether for our producer and supplier customers or our own account. We have no keep-whole arrangements with our customers. On our Gloria, Lafitte and Offshore Texas systems, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and subsequently transport that natural gas to delivery points on our systems at which we sell the natural gas at the same undiscounted index price thereby earning a fixed margin on each transaction. We regard the segment gross margin we earn with respect to those purchases and sales a “fixed-margin” and as the economic equivalent of a fee for our transportation service, and as such, we include these transactions in the category of fee-based contractual arrangements. In order to minimize commodity price risk we face in these transactions, we match sales with purchases at the index price on the date of settlement. For the year ended December 31, 2010, our fee-based and fixed-margin arrangements and our POP arrangements accounted for approximately 46.3% and 53.6%, respectively, of our segment gross margin for this segment. For the quarter ended March 31, 2011, our fee-based and fixed-margin arrangements and our POP arrangements accounted for approximately 39.0% and 61.0%, respectively, of our segment gross margin for this segment.

We continually seek new sources of raw natural gas supply to maintain and increase the throughput volume on our gathering systems and through our processing plants. As a result, we connected eleven new supply sources in 2010 to systems in our Gathering and Processing segment, including connections of individual wells, as well as central delivery points and interstate and intrastate pipelines that have multiple wells behind them.

Our Gathering and Processing assets are located in Alabama, Louisiana and Mississippi and in shallow state and federal waters in the Gulf of Mexico off the coasts of Louisiana and Texas.

Gloria System

The Gloria gathering system provides gathering and compression services through our assets, as well as processing services through our elective processing arrangements. The Gloria system is located in Lafourche, Jefferson, Plaquemines, St. Charles and St. Bernard parishes of Louisiana and consists of approximately 110 miles of pipeline with diameters ranging from three to 16 inches and three compressors with a combined capacity of 1,877 horsepower. The Gloria system has a design capacity of approximately 90 MMcf/d, but is currently limited by compression horsepower at the Gloria Compressor Station to approximately 60 MMcf/d.

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Average throughput on the Gloria system for the year ended December 31, 2010 was 36.6 MMcf/d from approximately 57 connected wells and an interconnect with our Lafitte system. Average throughput on the Gloria system increased to approximately 49.0 MMcf/d for the quarter ended March 31, 2011 due to excess volumes from our Lafitte system, primarily resulting from the completion of a new interconnect between the Lafitte system and TGP, an interstate pipeline owned by El Paso Corporation. For more information about the excess natural gas from our Lafitte system, please read “— Lafitte System.”

The Gloria system gathers natural gas from onshore oil and natural gas wells producing from the Gulf Coast region of Louisiana. Production is derived from a variety of reservoirs and ranges from dry natural gas to rich associated natural gas. Well decline rates are variable in this area, but it is common practice for producers to mitigate declines in production with workovers and re-completions of existing wells. An average of four wells per year were connected to the Gloria system over the last three years, with four wells connected during the year ended December 31, 2010. Producers generally bear the cost of connecting their wells to our Gloria system.

Toca Plant and Our Elective Processing Arrangements. The Toca plant is a cryogenic processing plant with a design capacity of approximately 1.1 Bcf/d that is located in St. Bernard Parish in Louisiana and operated by Enterprise. We entered into a new POP processing contract with Enterprise in July 2011 that replaced two month-to-month POP processing contracts with Enterprise and allows us to continue to process raw natural gas through the Toca plant, whether for our customers or our own account. This new contract has an initial term of seven years and covers volumes from both our Gloria and Lafitte systems. The new contract contains a tiered-pricing structure based on the volume of natural gas processed under which Enterprise retains a percentage of the NGLs produced by the Toca plant as payment for its processing services. Natural gas that is processed at the Toca plant is transported to end users via the Sonat pipeline directly and through various

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interconnects downstream of the Toca plant. Sonat is the primary pipeline into which Toca volumes are delivered.

Our month-to-month contracts with producers on the Gloria and Lafitte systems, as well as our ability to purchase natural gas at the Lafitte/TGP interconnect, provide us with the flexibility to decide whether to process natural gas through the Toca plant and capture processing margins for our own account or deliver the natural gas into the interstate pipeline market at the inlet to the Toca plant, and we make this decision based on the relative prices of natural gas and NGLs on a monthly basis. We refer to the flexibility built into these contracts as our elective processing arrangements. Due to currently strong processing margins, we currently process 100% of the natural gas purchased on the Gloria system, as well as any excess natural gas purchased via the Lafitte/TGP interconnect in excess of the needs of ConocoPhillips at the Alliance Refinery. Based on publicly available information, we believe that the Toca plant has sufficient capacity available to accommodate additional volumes from the Gloria system.

Lafitte System

The Lafitte gathering system consists of approximately 40 miles of gathering pipeline, with diameters ranging from four to 12 inches and a design capacity of approximately 71 MMcf/d. The Lafitte system originates onshore in southern Louisiana and terminates in Plaquemines Parish, Louisiana at the Alliance Refinery owned by ConocoPhillips Corporation, or ConocoPhillips. Average throughput on the Lafitte system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was 12.0 MMcf/d and 19.9 MMcf/d, respectively, from approximately 44 connected wells and an interconnect with TGP that was completed in December 2010. We are the sole supplier of natural gas to the Alliance Refinery through our Lafitte and Gloria systems. We supply natural gas to the Alliance Refinery pursuant to a long-term contract that expires in 2023. Any natural gas not used by ConocoPhillips at the Alliance Refinery is delivered to our Gloria system.

Like our nearby Gloria system, the Lafitte system gathers natural gas from onshore oil and natural gas wells producing from the Gulf Coast region of Louisiana. An average of three wells per year were connected to the Lafitte system over the last three years, with no wells connected during the year ended December 31, 2010. Producers generally bear the cost of connecting their wells to our Lafitte system.

TGP Interconnect. In December 2010, we completed an interconnect between our Lafitte pipeline and a pipeline on the TGP interstate system. This interconnect provides a redundant source of natural gas supply for the ConocoPhillips Alliance Refinery to the extent that the Lafitte native production is insufficient to supply the needs of the refinery and provides us with increased operational flexibility on our Gloria and Lafitte systems. To the extent that there is excess supply that the refinery does not consume, we purchase those volumes to be sold into Sonat pursuant to a fixed-margin arrangement or to be processed at the Toca processing facility pursuant to elective processing arrangements.

Bazor Ridge System

The Bazor Ridge gathering and processing system consists of approximately 160 miles of pipeline with diameters ranging from three to eight inches and three compressor stations with a combined compression capacity of 1,069 horsepower. Our Bazor Ridge system is located in Jasper, Clarke, Wayne and Greene Counties of Mississippi. The Bazor Ridge system also contains a cryogenic sour natural gas treating and processing plant located in Wayne County, Mississippi with a design capacity of approximately 22 MMcf/d and four inlet and one discharge compressor with approximately 5,218 of combined horsepower. We upgraded the turbo expander at the Bazor Ridge processing plant in June 2010, which resulted in a significant improvement in the plant’s NGL recoveries and provided us with greater operating flexibility during changing commodity price environments. We have POP arrangements with each of our customers on the Bazor Ridge system that generally also include a fee-based element for gathering and treating services. After processing, the residue natural gas is sold and delivered into the Destin Pipeline system, an interstate pipeline operated by Destin Pipeline Company, L.L.C., which has connections with a number of other interstate pipeline systems. We sell the NGLs we recover at the truck rack at the tailgate of the Bazor Ridge processing plant to Dufour

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Petroleum LP, an affiliate of Enbridge, pursuant to a month-to-month contract. The NGLs are sold on a Mt. Belvieu index-based price. Average throughput on the Bazor Ridge plant for the year ended December 31, 2010 was approximately 9.2 MMcf/d from 40 connected wells. Average throughput increased to approximately 13.6 MMcf/d for the quarter ended March 31, 2011 as a result of the completion of the Winchester lateral, which we describe below, in November 2010.

Winchester Lateral. In 2010, we built a new eight-inch diameter pipeline consisting of approximately nine miles of pipe, called the Winchester lateral, to serve the natural gas wells located in Wayne County, Mississippi owned by Venture Oil & Gas, Inc., or Venture, and other producers. The Winchester lateral allowed us to increase the effective throughput capacity of the Bazor Ridge gathering system by approximately 200% to approximately 25 MMcf/d. In conjunction with the construction of the Winchester lateral, we negotiated a five-year acreage dedication from Venture.

The natural gas supply for our Bazor Ridge system is derived primarily from rich associated natural gas produced from oil wells targeting the mature Upper Smackover formation. Production from the wells drilled in this area is generally stable with relatively modest decline rates. An average of one well per year was connected to our Bazor Ridge gathering system over the last three years, with no wells connected during the year ended December 31, 2010 and one well connected during the quarter ended March 31, 2011. Despite the low number of new wells connected, the generally stable production and relatively modest decline rates from this formation allow us to maintain steady throughput on our Bazor Ridge system. Given the recent and current commodity price environment for crude oil, we expect increasing drilling activity and resulting production in this area during 2011.

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Quivira System

The Quivira gathering system consists of approximately 34 miles of pipeline, with a 12-inch diameter mainline and several laterals ranging in diameter from six to eight inches. The system originates offshore of Iberia and St. Mary Parishes of Louisiana in Eugene Island Block 24 and terminates onshore in St. Mary Parish, Louisiana at a connection with the Burns Point processing plant, a cryogenic processing plant with a design capacity of 160 MMcf/d that is owned and operated by Enterprise. The Quivira system has a design capacity of approximately 140 MMcf/d. This system also includes an onshore condensate handling facility at Bayou Sale, Louisiana that is upstream of the Burns Point processing plant. Residue natural gas is sold into TGP or the Gulf South Pipeline system, an interstate pipeline owned by Boardwalk Pipeline Partners, LP.

The Quivira system is fully subscribed under a firm transportation arrangement through 2012, although a substantial proportion of the revenue is derived from volumetric and fee-based charges. Existing production in our gathering area above our current system capacity is transported on other systems that we believe offer producers less attractive economic alternatives to our customers. Average throughput on the Quivira system for the year ended December 31, 2010 was approximately 77.4 MMcf/d from 16 connected wells. Average throughput increased to approximately 113.5 MMcf/d for the quarter ended March 31, 2011 as a result of additional production added to the system from a new interconnect to a gathering system owned and operated by Contango Oil & Gas Company. We expect that the Quivira system will be operating at capacity for the remainder of 2011 and through 2012.

The Quivira system provides gathering services for natural gas wells and associated natural gas produced from crude oil wells operated by major and independent producers targeting multiple conventional production zones in the shallow waters of the Gulf of Mexico. Wells in this area have historically exhibited relatively low

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rates of decline throughout the life of the wells. The natural gas produced from these wells is typically natural gas with condensate. An average of three wells per year were connected to the Quivira system over the last three years, with three wells connected during the year ended December 31, 2010. Producers generally bear the cost of connecting their wells to our Quivira system.

Offshore Texas System

The Offshore Texas system consists of the GIGS and Brazos systems, two parallel gathering systems that share common geography and operating characteristics. The Offshore Texas system provides gathering and dehydration services to natural gas producers in the shallow waters of the Gulf of Mexico region offshore Texas.

The Offshore Texas system consists of approximately 56 miles of pipeline with diameters ranging from six to 16 inches and a design capacity of approximately 100 MMcf/d. Additionally, the Offshore Texas system has two onshore separation and dehydration units, each with a capacity of approximately 40 MMcf/d, that remove water and other impurities from the gathered natural gas before delivering it to our customers. The GIGS system originates offshore of Brazoria County, Texas in Galveston Island Block 343 and connects onshore to the Houston Pipeline system, an intrastate pipeline owned by Energy Transfer Partners, L.P. The Brazos system originates offshore of Brazoria County, Texas in Brazos Block 366 and connects onshore to the Dow Pipeline system, an interstate pipeline owned by Dow Chemical Company. Substantially all of the natural gas gathered on the Brazos system is delivered to Dow Chemical for use in its chemical plant located in Freeport, Texas pursuant to a month-to-month contract. Dow consumes significantly more natural gas than is provided by the Brazos system and we believe Dow may purchase additional volumes from the Brazos system.

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Average throughput on the Offshore Texas system for the year ended December 31, 2010 was 15.3 MMcf/d from approximately 22 connected wells. Average throughput increased to approximately 19.2 MMcf/d for the quarter ended March 31, 2011 as a result of recent recompletion activity on wells connected to the system.

All of the wells in this area are natural gas wells producing from the Gulf of Mexico shelf offshore Texas. An average of three wells per year were connected to the Offshore Texas system over the last three years, with no new wells connected during the year ended December 31, 2010. Producers generally bear the cost of connecting their wells to our Texas Offshore system.

Other Gathering and Processing Assets

Alabama Processing. The Alabama Processing system consists of two small skid-mounted treating and processing plants that we refer to, individually, as Atmore and Wildfork. These treating and processing plants are located in Escambia and Monroe Counties of Alabama, respectively, and have design capacities of 3 MMcf/d and 7 MMcf/d, respectively. The Atmore and Wildfork plants processed an average of 0.4 MMcf/d and 0.3 MMcf/d of natural gas, respectively, during the year ended December 31, 2010 and an average of 1.3 MMcf/d and 0.2 MMcf/d, respectively, during the quarter ended March 31, 2011.

Magnolia System. The Magnolia gathering system is a Section 311 intrastate pipeline that gathers coalbed methane in Tuscaloosa, Greene, Bibb, Chilton and Hale counties of Alabama and delivers this natural gas to an interconnect with the Transco Pipeline system, an interstate pipeline owned by The Williams Companies, Inc. The Magnolia system consists of approximately 116 miles of pipeline with small-diameter gathering lines and trunklines ranging from six to 24 inches in diameter and one compressor station with 3,328 horsepower. The Magnolia system has a design capacity of approximately 120 MMcf/d. Average throughput on the Magnolia system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 17.4 MMcf/d and 19.9 MMcf/d, respectively. The Magnolia system is also strategically located in the Floyd shale formation, a currently underdeveloped play that may have significant production potential in a higher natural gas price environment.

Our other gathering and processing systems include the Fayette and Heidelberg gathering systems, located in Fayette County, Alabama and Jasper County, Mississippi, respectively. The design capacities for these systems are approximately 5 MMcf/d and approximately 18 MMcf/d, respectively. Average throughput for these systems was approximately 0.5 MMcf/d and approximately 6.5 MMcf/d, respectively, during the year ended December 31, 2010, and approximately 0.5 MMcf/d and approximately 5.7 MMcf/d, respectively, during the quarter ended March 31, 2011. We also own a small Joule Thompson processing skid, called Stringer, that we lease to a producer in Wayne County, Mississippi.

Growth Opportunities

In our Gathering and Processing segment, we continually seek new sources of raw natural gas supply to increase the throughput volume on our gathering systems and through our processing plants. In addition, we seek to identify and evaluate economically attractive organic expansion and asset acquisition opportunities that leverage our existing asset footprint and strategic relationships with our customers. We also plan to opportunistically pursue strategic and accretive acquisitions within the midstream energy industry that are complementary to our existing asset base or that provide attractive potential returns in new operating regions or business lines. In addition to the projects that we expect to undertake in our forecast period, we are evaluating the following growth opportunities:


	•	the addition of compression to the Gloria system to accommodate expected new production from existing customers or increase the volumes purchased via the Lafitte/TGP interconnect, which we expect to increase the current capacity of the Gloria system by approximately 50%, to approximately 90 MMcf/d;

	•	the reconnection of our stranded Montegut lateral to the Gloria system to provide access to areas of existing production that we currently do not serve and potential access to a third-party processing plant,

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		which would allow us to connect new wells that would increase the volume of natural gas that we gather on the Gloria system;


	•	the addition of pipeline capacity on the Quivira system through the pursuit of near-system acquisitions and the installation of additional pipe or additional compression capacity; and

	•	the addition of compression capacity to the Wildfork plant on the Alabama Processing system in order to increase plant throughput.

Customers

Substantially all of the natural gas produced on our Lafitte system is sold to ConocoPhillips for use at its Alliance Refinery in Plaquemines Parish, Louisiana under a contract that expires in 2023. On our Bazor Ridge system, we have a POP arrangement with Venture Oil & Gas Co. that contains an acreage dedication under a contract that expires in 2015. We have a weighted-average remaining life of approximately two years on our fee-based contracts in this segment. The weighted-average remaining life on our POP contracts in this segment is approximately three years. For the year ended December 31, 2010, our Gathering and Processing segment derived 34%, 29% and 10% of its revenue from ConocoPhillips, EMUS and Dow Hydrocarbons and Resources, respectively, and 19% and 13% of its segment gross margin from arrangements with Contango Operators Inc. and Venture Oil & Gas Co., respectively. For the quarter ended March 31, 2011, our Gathering and Processing segment derived 59%, 15% and 8% of its revenue from ConocoPhillips, EMUS and Dow Hydrocarbons and Resources, respectively, and 15% and 23% of its segment gross margin from arrangements with Contango Operators Inc. and Venture Oil & Gas Co., respectively.

Transmission Segment

General

Our Transmission segment is comprised of interstate and intrastate pipelines that transport natural gas from interconnection points on other large pipelines to customers such as LDCs, electric utilities or direct-served industrial complexes, or to interconnects on other pipelines. Certain of our pipelines are subject to regulation by FERC and by state regulators. In this segment, we generally enter into firm transportation contracts with our shipper customers to transport natural gas sourced from large interstate or intrastate pipelines. Our Transmission segment assets are located in multiple parishes in Louisiana and multiple counties in Mississippi, Alabama and Tennessee.

In our Transmission segment, we contract with customers to provide firm and interruptible transportation services. In addition, we have a fixed-margin arrangement on our MLGT system whereby we purchase and sell the natural gas that we transport under this arrangement. For a description of the types of contracts that we enter into with the customers in our Transmission segment, please read “Industry Overview — Typical Midstream Contractual Arrangements.”

For our Midla and AlaTenn systems, which are interstate natural gas pipelines, the maximum and minimum rates for services are governed by each individual system’s FERC-approved tariff. In some cases, we agree to discount services or in certain cases we enter into negotiated rate agreements that, with FERC approval, can have rates or other terms that are different than those provided for in the FERC tariff. For our Bamagas and MLGT systems, which are intrastate pipelines providing interstate services under the Hinshaw exemption of the NGA, we negotiate service rates with each of our shipper customers.

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The table below sets forth certain information regarding the assets, contracts and revenue for each of the major systems comprising our Transmission segment, as of and for the year ended December 31, 2010:


										Percent of
	Tariff Revenue Composition									Design Capacity			Weighted
	Firm Transportation Contracts									Subscribed			Average
	Capacity						Interruptible			Under Firm			Remaining
	Reservation			Variable Use			Transportation			Transportation			Contract Life
Asset	Charges			Charges			Contracts			Contracts			(in Years)

Bamagas		100	%		—	%		—	%		44	%		9
AlaTenn		78	%		2	%		20	%		26	%		2
Midla		83	%		3	%		14	%		100	%(1)		1
MLGT(2)		—	%		—	%		100	%		15	%		1


(1)		Represents volumes subscribed under firm transportation contracts and design capacity on the mainline of our Midla system.

(2)		Includes fixed-margin arrangements.

Bamagas System

Our Bamagas system is a Hinshaw intrastate natural gas pipeline that travels west to east from an interconnection point with TGP in Colbert County, Alabama to two power plants owned by Calpine Corporation, or Calpine, in Morgan County, Alabama. The Bamagas system consists of 52 miles of high pressure, 30-inch pipeline with a design capacity of approximately 450 MMcf/d.

Average throughput on the Bamagas system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 151.5 MMcf/d and 180.9 MMcf/d, respectively. Currently, 100% of the throughput on this system is contracted under long-term firm transportation agreements. Calpine Corporation is the sole customer on the Bamagas system, with two firm transportation contracts providing for a total of 200 MMcf/d of firm transportation capacity. These contracts, which expire in 2020, ensure steady natural gas supply for the Morgan and Decatur Energy Centers in Morgan County, Alabama. These two natural gas-fired power plants were built in 2002 and 2003 and have a combined capacity of 1,502 megawatts. These generating facilities supply the Tennessee Valley Authority, or the TVA, with electricity under long-term contractual arrangements between Calpine Corporation and the TVA.

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AlaTenn System

The AlaTenn system is an interstate natural gas pipeline that interconnects with TGP and travels west to east delivering natural gas to industrial customers in northwestern Alabama, as well as the city gates of Decatur and Huntsville, Alabama. Our AlaTenn system has a design capacity of approximately 200 MMcf/d and is comprised of approximately 295 miles of pipeline with diameters ranging from three to 16 inches and includes two compressor stations with combined capacity of 3,665 horsepower. The AlaTenn system is connected to four receipt and 61 delivery points, including the Tetco Pipeline system, an interstate pipeline owned by Duke Energy Corporation, and the Columbia Gulf Pipeline system, an interstate pipeline owned by NiSource Gas Transmission and Storage. Average throughput on the AlaTenn system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 48.0 MMcf/d and 66.2 MMcf/d, respectively.

Midla System

Our Midla system is an interstate natural gas pipeline with approximately 370 miles of pipeline linking the Monroe Natural Gas Field in Northern Louisiana and interconnections with the Transco Pipeline system and Gulf South Pipeline system to customers near Baton Rouge, Louisiana. Our Midla system also has interconnects to Centerpoint, TGP and Sonat along a high-pressure lateral at the north end of the system, called the T-32 lateral.

Our Midla system is strategically located near the Perryville Hub, which is a major hub for natural gas produced in the Louisiana and broader Gulf Coast region, including natural gas from the Haynesville shale, Barnett shale, Fayetteville shale, Woodford shale and Deep Bossier formations of Northern Louisiana, Central Texas, Northern Arkansas, Eastern Oklahoma and East Texas, respectively. The Midla system is connected to nine receipt and 19 delivery points. Due to the numerous interstate pipeline connections and growing supply

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and demand dynamics in the surrounding regions, we believe that our location near the Perryville Hub provides us a strategic advantage in securing supplies of natural gas.

Natural gas generally flows from north to south on the Midla mainline from interconnections with other interstate pipelines to customers and end users. The Midla system consists of the following components:


	•	the northern portion of the system, including the T-32 lateral;

	•	the mainline; and

	•	the southern portion of the system, including interconnections with the MLGT system and other associated laterals.

The northern portion of the system, including the T-32 lateral, consists of approximately four miles of high pressure, 12-inch diameter pipeline. Natural gas on the northern end of the Midla system is delivered to two power plants operated by Entergy by way of the T-32 lateral and the CLECO Sterlington plant by way of the Sterlington lateral. These power plants are peak-load generating facilities that consumed an aggregate average of approximately 23.6 MMcf/d and 27.8 MMcf/d of natural gas for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively. The T-32 lateral is fully subscribed, with approximately 296 MMcf/d of firm transportation capacity under contracts with an average remaining term of 0.5 years that automatically renew on a year-to-year basis.

The mainline of the system has a design capacity of approximately 198 MMcf/d and consists of approximately 170 miles of low pressure, 22-inch diameter pipeline with laterals ranging in diameter from two to 16 inches. This section of the Midla system primarily serves small LDCs under firm transportation contracts that automatically renew on a year-to-year basis. Substantially all of these contracts are at maximum rates allowed under Midla’s FERC tariff. Average throughput on the Midla mainline for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 61.6 MMcf/d and 92.2 MMcf/d, respectively.

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The southern portion of the system, including interconnections with the MLGT system and other associated laterals, consists of approximately two miles of high and low pressure, 12-inch diameter pipeline. This section of the system primarily serves industrial and LDC customers in the Baton Rouge market through contracts with several large marketing companies. In addition, this section includes two small offshore gathering lines, the T-33 lateral in Grand Bay and the T-51 lateral in Eugene Island 28, each of which are approximately five miles in length. Natural gas delivered on the southern end of the system is sold under both firm and interruptible transportation contracts with average remaining terms of two years.

MLGT System

The MLGT system is an intrastate transmission system that sources natural gas from interconnects with the FGT Pipeline system, an interstate pipeline owned by Florida Gas Transmission Company, the Tetco Pipeline system, the Transco Pipeline system and our Midla system to a Baton Rouge, Louisiana refinery owned and operated by ExxonMobil and five other industrial customers. Our MLGT system has a design capacity of approximately 170 MMcf/d and is comprised of approximately 54 miles of pipeline with diameters ranging from three to 14 inches. The MLGT system is connected to seven receipt and 16 delivery points. Average throughput on the MLGT system for the year ended December 31, 2010 and the quarter ended March 31, 2011 was approximately 50.5 MMcf/d and 63.8 MMcf/d, respectively.

Other Systems

Our other transmission systems include the Chalmette system, located in St. Bernard Parish, Louisiana, and the Trigas system, located in three counties in northwestern Alabama. The approximate design capacities for the Chalmette and Trigas systems are 125 MMcf/d and 60 MMcf/d, respectively. The approximate average throughput for these systems was 6.0 MMcf/d and 5.9 MMcf/d, respectively, for the year ended December 31, 2010 and 0.5 MMcf/d and 11.9 MMcf/d, respectively, for the quarter ended March 31, 2011. Finally, we also own a number of miscellaneous interconnects and small laterals that are collectively referred to as the SIGCO assets.

Growth Opportunities

In our Transmission segment, we continually seek to increase the throughput volume on our pipelines. We also seek to identify and evaluate economically attractive organic expansion and asset opportunities that leverage our existing asset footprint and strategic relationships with our customers. In addition to the projects that we expect to undertake in our forecast period, we are evaluating the following growth opportunities:


	•	the addition of delivery points to the AlaTenn system, which we believe will improve overall system flexibility and allow us to capitalize on possible incremental natural gas demand from various electric utilities on our system who are either in the process of, or are evaluating, switching fuel sources from coal to natural gas; and

	•	the addition of LDC and industrial customers on the AlaTenn system who were commercially underserved by our Predecessor.

Customers

In our Transmission segment, we contract with LDCs, electric utilities, or direct-served industrial complexes, or to interconnections on other large pipelines, to provide firm and interruptible transportation services. Among all of our customers in this segment, the weighted-average remaining life of our firm and interruptible transportation contracts are approximately five years and less than one year, respectively. 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. In addition, our Transmission segment derived 38% and 30% of its gross margin from arrangements with Calpine Corporation for the year ended December 31, 2010 and the quarter ended March 31, 2011, respectively.

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Competition

The natural gas gathering, compression, treating and transportation business is very competitive. Our competitors in our Gathering and Processing segment include other midstream companies, producers, intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. Our major competitors in this segment include TGP and Gulf South.

In our Transmission segment, we compete with other pipelines that service regional markets, specifically in our Baton Rouge market. An increase in competition could result from new pipeline installations or expansions by existing pipelines. Competitive factors include the commercial terms, available capacity, fuel efficiencies, the interconnected pipelines and gas quality issues. Our major competitors for this segment are Southern Natural Gas Company, a subsidiary of El Paso Corporation and Louisiana Intrastate Gas, owned by Crosstex Energy, L.P.

Safety and Maintenance

We are subject to regulation by the PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, and the Pipeline Safety Improvement Act of 2002, or the PSIA, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas. New pipeline safety legislation requiring more stringent spill reporting and disclosure obligations has been introduced in the U.S. Congress and was passed by the U.S. House of Representatives in 2010, but was not voted on in the U.S. Senate. Similar legislation has been introduced in the current session of Congress, either independently or in conjunction with the reauthorization of the Pipeline Safety Act. In part as a result of the PG&E gas line explosion in California last year, the Department of Transportation 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 PHMSA’s announced intention to strengthen its rules. The PHMSA recently issued a final rule 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 through 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.

We regularly inspect our pipelines and third parties assist us in interpreting the results of the inspections.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. These state oil and gas standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

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In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

We and the entities in which we own an interest are also subject to:


	•	EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials;

	•	OSHA Process Safety Management Regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive materials; and

	•	Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities.

Regulation of Operations

Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.

Interstate Natural Gas Pipeline Regulation

Our interstate natural gas transportation systems are subject to the jurisdiction of the FERC under the Natural Gas Act of 1938, or the NGA. Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation of our interstate pipelines extends to such matters as:


	•	rates, services, and terms and conditions of service;

	•	the types of services offered to 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.

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Under the NGA, the rates for 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 FERC-approved tariffs. Pursuant to 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.

In 2008, FERC issued Order No. 717, a final rule that implements standards of conduct that include three primary rules: (1) the “independent functioning rule,” which requires transmission function and marketing function employees to operate independently of each other; (2) the “no-conduit rule,” which prohibits passing transmission function information to marketing function employees; and (3) the “transparency rule,” which imposes posting requirements to help detect any instances of undue preference. The FERC has since issued three rehearing orders which generally reaffirmed the determinations in Order No. 717 and also clarified certain provisions of the Standards of Conduct. A single rehearing request related to elective issues is currently pending before the FERC.

In 2005, the FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass through partnership entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. The policy statement provided that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. In August 2005, FERC dismissed requests for rehearing of its new policy statement. In December 2005, the FERC issued its first significant case-specific review of the income tax allowance issue in another pipeline partnership’s rate case. The FERC reaffirmed its income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The tax allowance policy and the December 2005 order were appealed to the United States Court of Appeals for the District of Columbia Circuit, or D.C. Circuit. The D.C. Circuit denied these appeals in May 2007 in ExxonMobil Oil Corporation v. FERC and fully upheld the FERC’s new tax allowance policy and the application of that policy in the December 2005 order. In 2007, the D.C. Circuit denied rehearing of its ExxonMobil decision. The ExxonMobil decision, its applicability and the issue of the inclusion of an income tax allowance have been the subject of extensive litigation before the FERC. Whether a pipeline’s owners have actual or potential income tax liability continues to be reviewed by FERC on a case-by-case basis. How the FERC applies ExxonMobil and the policy to pipelines owned by publicly traded partnerships could impose limits on a pipeline’s ability to include a full income tax allowance in its cost of service.

In April 2008, the FERC issued a Policy Statement regarding the composition of proxy groups for determining the appropriate return on equity for natural gas and oil pipelines using FERC’s Discounted Cash Flow, or “DCF,” model for setting cost-of-service or recourse rates. The FERC denied rehearing and no petitions for review of the Policy Statement were filed. In the policy statement, FERC concluded, among other matters that MLPs should be included in the proxy group used to determine return on equity for both oil and natural gas pipelines, but the long-term growth component of the DCF model should be limited to fifty percent of long-term gross domestic product. The adjustment to the long-term growth component, and all other things being equal, results in lower returns on equity than would be calculated without the adjustment. However, the actual return on equity for our interstate pipelines will depend on the specific companies included in the proxy group and the specific conditions at the time of the future rate case proceeding. FERC’s policy determinations applicable to MLPs are subject to further modification.

Section 311 Pipelines

Intrastate transportation of natural gas is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce without an exemption under the NGA, the rates, terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA, and Part 284 of the FERC’s regulations. Pipelines providing transportation service under Section 311 are required to provide services on an

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open and nondiscriminatory basis. The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates, terms and conditions of some transportation services provided on our Section 311 pipeline systems are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to the FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.

Hinshaw Pipelines

Intrastate natural gas pipelines are defined as pipelines that operate entirely within a single state, and generally are not subject to FERC’s jurisdiction under the NGA. Hinshaw pipelines, by definition, also operate within a single state, but can receive gas from outside their state without becoming subject to FERC’s NGA jurisdiction. Specifically, Section 1(c) of the NGA exempts from the FERC’s NGA jurisdiction those pipelines which transport gas in interstate commerce if (1) they receive natural gas at or within the boundary of a state, (2) all the gas is consumed within that state and (3) the pipeline is regulated by a state commission. Following the enactment of the NGPA, the FERC issued Order No. 63 authorizing Hinshaw pipelines to apply for authorization to transport natural gas in interstate commerce in the same manner as intrastate pipelines operating pursuant to Section 311 of the NGPA. Hinshaw pipelines frequently operate pursuant to blanket certificates to provide transportation and sales service under the FERC’s regulations.

Historically, FERC did not require intrastate and Hinshaw pipelines to meet the same rigorous transactional reporting guidelines as interstate pipelines. However, as discussed below, last year the FERC issued a new rule, Order No. 735, which increases FERC regulation of certain intrastate and Hinshaw pipelines. See “— Market Behavior Rules; Posting and Reporting Requirements.”

Gathering Pipeline Regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. However, some of our natural gas gathering activity is subject to Internet posting requirements imposed by FERC as a result of FERC’s market transparency initiatives. We believe that our natural gas pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. 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, 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 such companies transferring gathering facilities to 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. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

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Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to these regulations.

Market Behavior Rules; Posting and Reporting Requirements

On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or the EPAct 2005. Among other matters, the EPAct 2005 amended the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC and, furthermore, provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of the EPAct 2005, and subsequently denied rehearing. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. The EPAct 2005 also amends the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes, up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines.

The EPAct of 2005 also added a section 23 to the NGA authorizing the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. In 2007, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of annual quantities of natural gas of 2,200,000 MMBtu or more, including entities not otherwise subject to FERC jurisdiction, to submit on May 1 of each year an annual report to FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. In June 2010, the FERC issued the last of its three orders on rehearing and clarification further clarifying its requirements.

In 2008, the FERC issued Order No. 720 which increases the Internet posting obligations of interstate pipelines, and also requires “major non-interstate” pipelines (defined as pipelines that are not natural gas

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companies under the NGA that deliver more than 50 million MMBtu annually) to post on the Internet the daily volumes scheduled for each receipt and delivery point on their systems with a design capacity of 15,000 MMBtu per day or greater. Numerous parties requested modification or reconsideration of this rule. An order on rehearing, Order No. 720-A, was issued on January 21, 2010. In that order the FERC reaffirmed its holding that it has jurisdiction over major non-interstate pipelines for the purpose of requiring public disclosure of information to enhance market transparency. Order No. 720-A also granted clarification regarding application of the rule. Two parties have filed appeals of Order Nos. 720 and 720-A to the Fifth Circuit. The parties have filed briefs but no decision has been issued.

In May 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through a new electronic reporting system and will be posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the Commission’s periodic review of the rates charged by the subject pipelines from three years to five years. Order No. 735 becomes effective on April 1, 2011. In December 2010, the Commission issued Order No. 735-A. In Order No. 735-A, the Commission generally reaffirmed Order No. 735 requiring section 311 and “Hinshaw” pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract.

In July 2010, for the first time the FERC issued an order finding that the prohibition against buy/sell arrangements applies to interstate open access services provided by Section 311 and Hinshaw pipelines. The FERC denied numerous requests for rehearing and motions for late interventions that were filed in response to the July order. However, in October 2010, the FERC issued a Notice of Inquiry seeking public comment on the issue of whether and how parties that hold firm capacity on some intrastate pipelines can allow others to use their capacity, including to what extent buy/sell transactions should permitted and whether the FERC should consider requiring such pipelines to offer capacity release programs. In the Notice of Inquiry, the FERC granted a blanket waiver regarding such transactions while the FERC is considering these policy issues. The comment period has ended but the FERC has not yet issued an order.

Offshore Natural Gas Pipelines

Our offshore natural gas gathering pipelines are subject to federal regulation under the Outer Continental Shelf Lands Act, which requires that all pipelines operating on or across the outer continental shelf provide open and nondiscriminatory access to shippers. From 1982 until 2010, the Minerals Management Service, or MMS, of the U.S. Department of the Interior, or DOI, was the federal agency that managed the nation’s oil, natural gas, and other mineral resources on the outer continental shelf, which is all submerged lands lying seaward of state coastal waters which are under U.S. jurisdiction, and collected, accounted for, and disbursed revenues from federal offshore mineral leases. On June 18, 2010, the Minerals Management Service was renamed the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE. The BOEMRE currently regulates offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the outer continental shelf, and removal of facilities. On January 19, 2011, the U.S. Department of the Interior announced the structures and responsibilities of the two remaining agencies, with the reorganization of BOEMRE into these agencies to be completed by October 1, 2011. Once the reorganization is complete, the BOEMRE will cease to exist. At this time, we cannot predict the impact that this reorganization, or future regulations or enforcement actions taken by the new agencies, may have on our operations.

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Sales of Natural Gas and NGLs

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the NGA, the NGPA, and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission, or the CFTC, and the Federal Trade Commission, or FTC. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Sales of NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.

As discussed above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate natural gas pipelines and those initiatives may also affect the intrastate transportation of natural gas both directly and indirectly.

Environmental Matters

General

Our operation of pipelines, plants and other facilities for the gathering, compressing, treating and transporting of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:


	•	requiring the installation of pollution-control equipment or otherwise restricting the way we operate;

	•	limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

	•	delaying system modification or upgrades during permit reviews;

	•	requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and

	•	enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the

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amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Substances and Waste

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

We currently own or lease, and our Predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Oil Pollution Act

In January of 1974, the EPA adopted regulations under the OPA. These oil pollution prevention regulations require the preparation of a Spill Prevention Control and Countermeasure Plan or SPCC for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing,

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using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We believe that our facilities will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Air Emissions

Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations and processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. Other than as described below with respect to our Bazor Ridge plant, we believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Our Bazor Ridge processing plant processes natural gas that is high in hydrogen sulfide, or H₂S. This plant has a Title V Air Permit, which is a permit issued pursuant to Title V of the federal Clean Air Act for larger sources of air emissions. In Mississippi, where the Bazor Ridge plant is located, the Title V program is administered by the Mississippi Department of Environmental Quality, or the MDEQ. Under this permit, we are allowed to emit up to a specified level of sulfur dioxide, or SO₂, per year.

In the course of preparing our annual MDEQ filing for 2010 as required by our Title V Air Permit, we recently determined that we underreported to MDEQ the SO₂ emissions from the Bazor Ridge plant for 2009 and 2010. Moreover, we recently discovered that SO₂ emission levels during 2009 may have exceeded the threshold that triggers the need for a Prevention of Significant Deterioration, or a PSD, permit under the federal Clean Air Act. No PSD permit has been issued for the Bazor Ridge plant. In addition, we recently determined that certain SO₂ emissions during 2009 and 2010 exceeded the reportable quantity threshold under the federal Emergency Planning and Community Right-to-Know Act, or EPCRA, requiring notification of various governmental authorities. We did not make any such EPCRA notifications. We recently self-reported these issues to the MDEQ and the EPA. If the MDEQ or the EPA were to initiate enforcement proceedings with respect to 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. If the Bazor Ridge plant were subject to any curtailment or other operational restrictions as a result of any such enforcement proceeding, or were required to incur additional capital expenditures for additional emission controls through any permitting process, the costs to us could be material. Although we cannot presently predict the outcome of any enforcement proceedings, any monetary sanctions, operational limitations or restrictions or additional permitting requirements could, either individually or in the aggregate, be materially adverse to us. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook — Impact of Bazor Ridge Emissions Matter” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Impact of Bazor Ridge Emissions Matter.”

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In additional to potential procedural changes at our Bazor Ridge plant, we may seek an increase in the level of permitted SO₂ emissions in order to avoid exceeding our Title V Air Permit in the future. This process involves public comment periods and a technical review. If the application is successful, an amended Title V Air Permit would be issued. This process typically takes approximately nine months to complete. We do not expect that we will be required to suspend or curtail our operations at the Bazor Ridge plant during any such application process.

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 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.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flow.

Safe Drinking Water Act

The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We own and operate an acid gas disposal

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well in Wayne County, Mississippi as part of our Bazor Ridge gas treating facilities. This well takes a combination of hydrogen sulfide and carbon dioxide recovered from the raw field natural gas feeding the Bazor Ridge Gas plant and injects it into an underground formation permitted for this purpose. The well received an Underground Injection Control (UIC) Class 2 permit through the Mississippi state oil and gas board in 1999. As part of our permit requirements, we perform regular inspection, maintenance and reporting to the state on the condition and operations of this well which is adjacent to our processing plant. We believe that our facilities will not be materially adversely affected by such requirements.

Endangered Species

The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

National Environmental Policy Act

The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance, and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews which may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

In the U.S., legislative and regulatory initiatives are underway to limit GHG emissions. The U.S. Congress has considered legislation that would control GHG emissions through a “cap and trade” program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act, or the CAA, definition of an “air pollutant,” and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. In 2010, the EPA 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.

In addition, on September 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources in the U.S. beginning in 2011 for emissions 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 to include onshore and offshore oil and natural gas systems beginning in 2012. 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.

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Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. In addition to these regulatory developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Due to their location, our operations along the Gulf Coast are vulnerable to operational and structural damages resulting from hurricanes and other severe weather systems and our insurance may not cover all associated losses. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Anti-terrorism Measures

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. Three of our facilities have more than the threshold quantity of listed chemicals; therefore, a “Top Screen” evaluation was submitted to the DHS. The DHS reviewed this information and made the determination that none of the facilities are considered high-risk chemical facilities.

Title to Properties and Rights-of-Way

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. Our Predecessors leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership in such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

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MANAGEMENT

We are managed by the directors and executive officers of our general partner, American Midstream GP. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. AIM Midstream Holdings owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly participate in our management or operations. AIM, Eagle River Ventures, LLC, Stockwell Fund II, L.P. and certain of our executive officers own all of the membership interests in AIM Midstream Holdings. In addition, Messrs. Hellman, Carbone and Diffendal serve on the board of directors of our general partner and are principals of and have ownership interests in AIM. Our general partner owes certain fiduciary duties to our unitholders. 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, we intend to incur indebtedness that is nonrecourse to our general partner.

Our partnership agreement provides for the conflicts committee of the board of directors of our general partner, or the Conflicts Committee, as delegated by the board of directors of our general partner as circumstances warrant, to review conflicts of interest between us and our general partner or between us and affiliates of our general partner. If a matter is submitted to the Conflicts Committee, which will consist solely of independent directors, for their review and approval, the Conflicts Committee will determine if the resolution of a conflict of interest that has been presented to it by the board of directors of our general partner is fair and reasonable to us. The members of the Conflicts Committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates. In addition, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act for service on an audit committee of a board of directors. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, the board of directors of our general partner will have an audit committee, or the Audit Committee, that complies with the NYSE requirements, and a compensation committee of the board of directors, or the Compensation Committee.

Even though most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of its general partner.

L. Kent Moore, Matthew P. Carbone, David L. Page, Edward O. Diffendal and Gerald A. Tywoniuk will serve as the initial members of the Audit Committee. Mr. Tywoniuk serves as the chairman of the Audit Committee. In compliance with the rules of the NYSE, the members of the board of directors will appoint two additional independent members to the board of directors, one within 90 days of this offering and a second within twelve months of this offering. Messrs. Carbone and Page will resign from the Audit Committee upon appointment of the first such additional independent director to the board of directors and the Audit Committee. Mr. Diffendal will resign from the Audit Committee when the final independent director is appointed. Thereafter, our general partner is generally required to have at least three independent directors serving on its board at all times.

Robert B. Hellman, Jr. and L. Kent Moore serve as the members of the Compensation Committee. Robert B. Hellman, Jr. serves as the chairman of the Compensation Committee.

Robert B. Hellman, Jr., Matthew P. Carbone and David L. Page serve as the members of the Compliance Committee. Robert B. Hellman, Jr. serves as the chairman of the Compliance Committee.

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Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board. The following table shows information for the directors and executive officers of our general partner.


Name	Age		Position with American Midstream GP, LLC

Robert B. Hellman, Jr.		53	Chairman of the Board
Brian F. Bierbach		53	Director, President and Chief Executive Officer
Sandra M. Flower		52	Vice President of Finance
John J. Connor II		54	Senior Vice President of Operations and Engineering
Marty W. Patterson		52	Senior Vice President of Commercial Services
William B. Mathews		59	Secretary, General Counsel and Vice President of Legal Affairs
Matthew P. Carbone		45	Director
Edward O. Diffendal		42	Director
David L. Page		76	Director
L. Kent Moore		55	Director
Gerald A. Tywoniuk		49	Director

Robert B. Hellman, Jr. was elected Chairman of the board of directors of our general partner in November 2009. Mr. Hellman has been a Managing Director of AIM since he co-founded AIM in July of 2006. Prior to co-founding AIM, Mr. Hellman was a Managing Director of McCown De Leeuw & Co., a private equity firm based in Foster City, California since 1986. Mr. Hellman is also chairman of the Board of Directors of Stonemor Partners L.P. Mr. Hellman received an MBA from Harvard University, an M.A. in Economics from the London School of Economics and a B.A. in Economics from Stanford University. We believe that Mr. Hellman’s over 20 years of investing experience, as well as his in-depth knowledge of the midstream natural gas industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner.

Brian F. Bierbach was appointed President and Chief Executive Officer, and elected as a member of the board of directors, of our general partner in November 2009. Prior to our formation, Mr. Bierbach served as President and as a member of the board of directors of Foothills Energy Ventures, LLC, a private midstream natural gas asset development and operating company, from 2006 to 2009. Mr. Bierbach has also served as President of Cinergy Canada, Inc. from 2003 to 2005 and President of Bear Paw Energy, LLC, a subsidiary of Northern Border Partners, L.P., from 2000 to 2002. He also held various positions with Enron Corporation, The Williams Companies, Inc., Apache Corporation and ConocoPhillips. He received a B.S. in Civil Engineering from the University of Arizona. We believe that Mr. Bierbach’s experience as President and Chief Executive Officer of our general partner and related familiarity with our assets as well as his extensive knowledge of the midstream natural gas industry provide him with the necessary skills to be a member of the board of directors of our general partner.

Sandra M. Flower has served as Vice President of Finance of our general partner since November 2009. Ms. Flower also served as our Controller from November 2009 until March 2011. Prior to our formation, Ms. Flower served as Group Controller at TransMontaigne, Inc. and as Director of Internal Audit for TransMontaigne Partners, LP from 2005 to 2009. While at TransMontaigne, she was responsible for trading support, credit, accounting and consolidation activities of TransMontaigne Inc., as well as supervising the design and implementation of all internal audit activities including Sarbanes-Oxley compliance procedures. Ms. Flower began her career at Touche Ross & Co. She received a B.S.B.A. from the University of Rhode Island and is a CPA.

John J. Connor II has served as Senior Vice President of Operations and Engineering of our general partner since November 2009. Prior to our formation, Mr. Connor served as Vice President of Development at Foothills Energy Ventures, LLC. Prior to Foothills, he was Director of Midstream Operations at Black Hills Midstream, LLC from 2006 to 2007 and held various Director and General Manager positions at El Paso Corporation from 1980 to 2004. Mr. Connor received his B.S. in Civil Engineering from Colorado State University and is a licensed professional engineer.

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Marty W. Patterson has served as Senior Vice President of Commercial Services of our general partner since November 2009. Prior to our formation, he served as Vice President of Commercial Operations at Foothills Energy Ventures, LLC from 2006 to 2009. Prior to joining Foothills, Mr. Patterson was the Director of Commercial Operations with Cinergy Corp. from 2004 to 2006. Before that, he was the Senior VP Energy Services, IDACORP Energy, L.P. from 1997 to 2003, and held various other positions, focused on operations. Mr. Patterson received his degree in Petroleum Technology from Kilgore College and is currently a board member of the North American Energy Standards Board.

William B. Mathews has served as Secretary and Vice President of Legal Affairs of our general partner since November 2009 and General Counsel of our general partner since March 2011. Prior to our formation, he served as Vice President, General Counsel and Secretary of Foothills Energy Ventures, LLC from December 2006 to November 2009, as well as a director from August 2009 to November 2009. Prior to Foothills, Mr. Mathews served as Assistant General Counsel for ONEOK Partners, L.P., Northern Border Partners, L.P. and Bear Paw Energy, LLC from July 2001 to December 2006 and, previous to that, as Vice President and General Counsel of Duke Energy Field Services (now DCP Midstream, LLC) until 2000, having joined a predecessor company in 1985. He received a J.D. from the University of Denver and a B.S. in Civil Engineering from the University of Colorado.

Matthew P. Carbone was elected as a member of the board of directors of our general partner in November 2009. Mr. Carbone has been a Managing Director of AIM since he co-founded AIM in July 2006. Prior to co-founding AIM, from January 2005 until July 2006, Mr. Carbone was a Managing Director of McCown De Leeuw & Co., or MDC. Mr. Carbone has spent nearly 20 years in private equity and investment banking. Prior to MDC he led Wit Capital Group’s West Coast operations and worked in the investment banking divisions of Morgan Stanley, First Boston Corporation and Smith Barney. Mr. Carbone is also a member of the board of directors of the general partner of Oxford Resource Partners L.P. He received an MBA from Harvard Business School and a B.A. in Neuroscience from Amherst College. We believe that Mr. Carbone’s nearly 20 years of experience in corporate finance, as well as his in-depth knowledge of the midstream natural gas industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner.

Edward O. Diffendal was elected as a member of the board of directors of our general partner in November 2009. Mr. Diffendal has been a Principal with AIM since September 2007. Prior to joining AIM he served as a management consultant from 2005 to 2007, held various operating positions at Veritas Software Corp. from 2003 to 2005, was a Vice President at Broadview Capital Partners, L.P. from 2000 to 2003 and was a consultant at Monitor Company from 1991 to 1998. Mr. Diffendal received an MBA from Dartmouth College and M.A. and B.A. degrees in Economics from Stanford University. We believe that Mr. Diffendal’s over 10 years of experience in corporate finance, as well as his in-depth knowledge of the midstream natural gas industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner.

David L. Page was elected as a member of the board of directors of our general partner in February 2010. Mr. Page also serves as Chairman of the Executive Committee and a member of the Audit Committee of our General Partner. Mr. Page has served as a management consultant since February 2002. Prior to working as a management consultant, Mr. Page served as Chairman and Chief Executive Officer of Distribution Dynamics, Inc. from January 2000 until February 2002. His earlier career included a variety of management roles at McCown De Leeuw & Co. from 1994 through 2000. Prior to joining McCown De Leeuw & Co., Mr. Page was President and Chief Executive Officer of Page Packaging Corporation from 1987 through 1993, and Vice President and General Manager of Boise Cascade Corporation from 1959 through 1987. Mr. Page received a B.A. in Business Administration and Economics from Whitman College and completed the Executive Program at Stanford University. We believe that Mr. Page’s over 20 years of operating experience, as well as his in-depth knowledge of our partnership, provide him with the necessary skills to be a member of the board of directors of our general partner

L. Kent Moore was elected as a member of the board of directors of our general partner in November 2009. Mr. Moore owns Eagle River Ventures, LLC, which holds mostly oil and gas investments and a 0.5%

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interest in AIM Midstream Holdings. From 2006 through 2011, Mr. Moore served as chairman of the board of directors of Foothills Energy Ventures, LLC. He also serves as chairman of the board of trustees for the Old Mutual Funds I and II, and also a trustee of the TS&W/Claymore Long Short Fund. He has also served as a portfolio manager and vice-president at Janus Capital, and as analyst/portfolio manager for Marsico Capital Management, focusing on technology and energy stocks. Before working in the mutual fund industry, Mr. Moore was a vice-president with Exeter Drilling Company and also co-founded and was President of Caza Drilling Company. Mr. Moore received a B.S. in Industrial Management from Purdue University. We believe that Mr. Moore’s over 20 years of investing and operating experience, as well as his in-depth knowledge of the midstream natural gas industry generally and our partnership in particular, provide him with the necessary skills to be a member of the board of directors of our general partner.

Gerald A. Tywoniuk was elected as a member of the board of directors of our general partner in May 2011. Mr. Tywoniuk also serves as Chairman of the Audit Committee of our general partner. With respect to the Audit Committee, he also qualifies as an “audit committee financial expert.” Mr. Tywoniuk has nearly 30 years of management, finance and accounting experience and has held various positions in public energy master limited partnerships. Mr. Tywoniuk serves as a director of the general partner of Oxford Resource Partners, LP. Mr. Tywoniuk has served as interim Senior Vice President, Finance of CIBER, Inc., a global information technology services company, since May 2010. Prior to CIBER, he held various management and finance roles, including acting Chief Executive Officer and Chief Financial Officer of Pacific Energy Resources Ltd. from 2008 to 2010, independent financial consultant in 2007, Senior Vice President and Chief Financial Officer of Pacific Energy Partners, LP., where he assisted with the integration of the company after it was acquired by Plains All American Pipeline, L.P., from 2002 to 2006 and Senior Vice President, Chief Financial Officer and a member of the board of directors of the general partner of MarkWest Energy Partners, L.P. and MarkWest Hydrocarbon, Inc. from 1997 to 2002. Mr. Tywoniuk received a B.Comm from the University of Alberta and is a Canadian chartered accountant. We believe that Mr. Tywoniuk’s 29 years of accounting, financial and executive management experience, as well as his in-depth knowledge of the midstream natural gas industry, and his prior experience with publicly traded partnerships, provide him with the necessary skills to be a member of the board of directors of our general partner.

Compensation Discussion and Analysis

Our general partner, under the direction of its board of directors, or the Board, is responsible for managing our operations and employs all of the employees that operate our business. The compensation payable to the officers of our general partner is paid by our general partner and such payments are reimbursed by us on a dollar-for-dollar basis. See “The Partnership Agreement — Reimbursement of Expenses.”

The following is a discussion of the compensation policies and decisions of the Compensation Committee of the Board, with respect to the following individuals, who are executive officers of our general partner and referred to as the “named executive officers” for the fiscal year ended December 31, 2010:


	•	Brian F. Bierbach, President and Chief Executive Officer;

	•	Sandra M. Flower, Vice President of Finance;

	•	John J. Connor II, Senior Vice President of Operations and Engineering;

	•	Marty W. Patterson, Senior Vice President of Commercial Services; and

	•	William B. Mathews, Secretary, General Counsel and Vice President of Legal Affairs.

Our compensation program is designed to recruit and retain as executive officers individuals with the highest capacity to develop, grow and manage our business, and to align their compensation with our short-term and long-term goals. To do this, our compensation program for executive officers is made up of the following main components: (i) base salary, designed to compensate our executive officers for work performed during the fiscal year; (ii) short-term incentive programs, designed to reward our executive officers for our yearly performance and for their individual performances during the fiscal year; and (iii) equity-based awards, meant to align our executive officers’ interests with our long-term performance. Going forward, we expect that the Compensation Committee will continue to focus on these same components, although the Compensation

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Committee may consider whether changes to the types of compensation provided may be appropriate in order to more accurately reflect a compensation program appropriate for a publicly-traded entity.

This section should be read together with the compensation tables that follow, which disclose the compensation awarded to, earned by or paid to the named executive officers with respect to the year ended December 31, 2010.

Role of the Board, the Compensation Committee and Management

The Board has appointed the Compensation Committee to assist the Board in discharging its responsibilities relating to compensation matters, including matters relating to compensation programs for directors and executive officers of the general partner. The Compensation Committee has overall responsibility for evaluating and approving our compensation plans, policies and programs, setting the compensation and benefits of executive officers, and granting awards under and administering our equity compensation plans. The Compensation Committee is charged with, among other things, establishing compensation practices and programs that are (i) designed to attract, retain and motivate exceptional leaders, (ii) structured to align compensation with our overall performance and growth in distributions to unitholders, (iii) implemented to promote achievement of short-term and long-term business objectives consistent with our strategic plans, and (iv) applied to reward performance.

As described in further detail below under “— Elements of the Compensation Programs,” the compensation programs for our executive officers consist of base salaries, annual incentive bonuses and awards under the American Midstream GP, LLC Long-Term Incentive Plan, which we refer to as our LTIP, currently in the form of equity-based phantom units, as well as other customary employment benefits such as a 401(k) plan and health and welfare benefits. We expect that, following the completion of this offering, total compensation of our executive officers and the components and allocation among components of their annual compensation will be reviewed on at least an annual basis by the Compensation Committee.

During 2010 and 2011, the Compensation Committee discussed executive compensation issues at several meetings, and the Compensation Committee expects to hold additional executive compensation-related meetings in 2011 and in future years. Topics discussed and to be discussed at these meetings included and will include, among other things, (i) assessing the performance of the Chief Executive Officer, or the CEO, and other executive officers with respect to our results for the prior year, (ii) reviewing and assessing the personal performance of the executive officers for the preceding year and (iii) determining the amount of the bonus pool to be paid to our executive officers for a given year after taking into account the target bonus amounts established for those executive officers at the outset of the year. In addition, at these meetings, and after taking into account the recommendations of our CEO only with respect to executive officers other than our CEO, base salary levels and target bonus amounts (representing the bonus that may be awarded expressed as a dollar amount or as a percentage of base salary for the year) for all of our executive officers will be established by the Compensation Committee. In addition, the Compensation Committee will make its decisions with respect to any awards under the LTIP. We expect that our CEO will provide periodic recommendations to the Compensation Committee regarding the performance and compensation of the other named executive officers.

Compensation Objectives and Methodology

The principal objective of our executive compensation program is to attract and retain individuals of demonstrated competence, experience and leadership who share our business aspirations, values, ethics and culture. A further objective is to provide incentives to and reward our executive officers and other key employees for positive contributions to our business and operations, and to align their interests with our unitholders’ interests.

In setting our compensation programs, we consider the following objectives:


	•	to create unitholder value through sustainable earnings and cash available for distribution;

	•	to provide a significant percentage of total compensation that is “at-risk” or variable;

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	•	to encourage significant equity holdings to align the interests of executive officers and other key employees with those of unitholders;

	•	to provide competitive, performance-based compensation programs that allow us to attract and retain superior talent; and

	•	to develop a strong linkage between business performance, safety, environmental stewardship, cooperation and executive compensation.

Taking account of the foregoing objectives, we structure total compensation for our executives to provide a guaranteed amount of cash compensation in the form of competitive base salaries, while also providing a meaningful amount of annual cash compensation that is at risk and dependent on our performance and individual performances of the executives, in the form of discretionary annual bonuses. We also seek to provide a portion of total compensation in the form of equity-based awards under our LTIP, in order to align the interests of executives and other key employees with those of our unitholders and for retention purposes. Historically, we have not made regular annual grants of awards under our LTIP. To date, the only awards under our LTIP were made in connection with our formation, although certain of these grants were made in 2010. Going forward, we expect that equity-based awards will be made more regularly and that equity-based awards will become more prominent in our annual compensation decision-making process.

Compensation decisions for individual executive officers are the result of the subjective analysis of a number of factors, including the individual executive officer’s experience, skills or tenure with us and changes to the individual executive officer’s position. In evaluating the contributions of executive officers and our performance, although no pre-determined numerical goals were established, a variety of financial measures have been generally considered, including non-GAAP financial measures used by management to assess our financial performance, such as adjusted EBITDA and cash available for distribution. For a definition of adjusted EBITDA, please read “Selected Historical Consolidated Financial and Operating Data.” For a discussion of the general concept of “cash available for distribution,” please read “Our Cash Distribution Policy and Restrictions on Distributions.” In addition, a variety of factors related to the individual performance of the executive officer were taken into consideration.

In making individual compensation decisions, the Compensation Committee historically has not relied on pre-determined performance goals or targets. Instead, determinations regarding compensation have been the result of the exercise of judgment based on all reasonably available information and, to that extent, were discretionary. Each executive officer’s current and prior compensation is considered in setting future compensation. The amount of each executive officer’s current compensation will be considered as a base against which determinations are made as to whether increases are appropriate to retain the executive officer in light of competition or in order to provide continuing performance incentives. Subject to the provisions contained in the executive officer’s employment agreement, if any, the Compensation Committee has discretion to adjust any of the components of compensation to achieve our goal of recruiting, promoting and retaining as executive officers, individuals with the skills necessary to execute our business strategy and develop, grow and manage our business.

To date, we have not reviewed executive compensation against a specific group of comparable companies or publicly traded partnerships. Rather, the Compensation Committee has historically relied upon the judgment and industry experience of its members in making decisions with respect to total compensation and with respect to the allocation of total compensation among our three main components of compensation. Going forward, we expect that the Compensation Committee will make compensation decisions taking into account trends occurring within our industry, including from a peer group of companies, which we expect will include the following similar publicly traded partnerships: Boardwalk Pipeline Partners, LP, Regency Energy Partners LP, Targa Resources Partners LP, MarkWest Energy Partners LP, Copano Energy LLC, Crosstex Energy LP, and Atlas Pipeline Partners LP. Additionally, we expect that the Compensation Committee will take into account trends occurring within a group of publicly traded energy companies with market capitalizations in the same range as our own, including from a peer group of companies, which we expect will include the following similar publicly-traded energy companies: Contango Oil & Gas Co., Goodrich Petroleum Corp., Kodiak Oil & Gas Corp., Magnum Hunter Resources Corp., Penn Virginia Corp., Resolute Energy

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Corporation, Approach Resources, Inc., PetroQuest Energy Inc. and Rex Energy Corporation. To date, the Compensation Committee has not retained the services of any compensation consultants.

Elements of the Compensation Programs

Overall, the executive officer compensation programs are designed to be consistent with the philosophy and objectives set forth above. The principal elements of our executive officer compensation programs are summarized in the table below, followed by a more detailed discussion of each compensation element.


Element	Characteristics	Purpose

Base Salaries	Fixed annual cash compensation. Executive officers are eligible for periodic increases in base salaries. Increases may be based on performance or such other factors as the Compensation Committee may determine.	Keep our annual compensation competitive with the defined market for skills and experience necessary to execute our business strategy.
Annual Incentive Bonuses	Performance-related annual cash incentives earned based on our objectives and individual performance of the executive officers. We expect that trends for our peer group will be taken into account in setting future annual cash incentive awards for our executive officers.	Align performance to our objectives that drive our business and reward executive officers for our yearly performance and for their individual performances during the fiscal year.
Equity-Based Awards (Phantom-units and Distribution Equivalent Rights)	Performance-related, equity-based awards granted at the discretion of the Compensation Committee. Awards are based on our performance and we expect that, going forward, will take into account competitive practices at peer companies. Grants typically consist of phantom units that vest ratably over four years and may be settled upon vesting with either a net cash payment or an issuance of common units, at the discretion of the Board. Historically, the Board has issued common units upon vesting of phantom units. Distribution Equivalent Rights, or DERs, which have been granted in conjunction with such phantom unit awards, entitle the grantee to receive cash distributions on unvested LTIP awards to the same extent generally as unitholders receive cash distributions on our common units.	Align interests of executive officers with unitholders and motivate and reward executive officers to increase unitholder value over the long term. Ratable vesting over a four-year period is designed to facilitate retention of executive officers. Issuance of common units upon vesting encourages equity ownership in order to align interests of executive officers with those of unitholders. DERs provide a clear, objective link between growing distributions to unitholders and executive compensation. (1)
Retirement Plan	Qualified retirement plan benefits are available for our executive officers and all other regular full-time employees. At our formation, we adopted and are maintaining a tax-deferred or after-tax 401(k) plan in which all eligible employees can elect to defer compensation for retirement up to IRS imposed limits. The 401(k) plan permits us to make annual discretionary matching contributions to the plan. For 2010, we matched employee contributions to 401(k) plan accounts up to a maximum employer contribution of 6% of the employee’s eligible compensation.	Provide our executive officers and other employees with the opportunity to save for their future retirement.

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Element	Characteristics	Purpose

Health and Welfare Benefits	Health and welfare benefits (medical, dental, vision, disability insurance and life insurance) are available for our executive officers and all other regular full-time employees.	Provide benefits to meet the health and wellness needs of our executive officers and other employees and their families.


(1)		On June 9, 2011, we amended each of the outstanding phantom unit grant agreements with our named executive officers to eliminate the DERs previously granted with our phantom units in exchange for a one-time aggregate payment of approximately $1.6 million. We do not expect to use grants of DERs as an element of our compensation programs in the future.

Base Salaries

Base salaries for our executive officers will be determined annually by an assessment of our overall financial and operating performance, each executive officer’s performance evaluation and changes in executive officer responsibilities. While many aspects of performance can be measured in financial terms, senior management will also be evaluated in areas of performance that are more subjective. These areas include the development and execution of strategic plans, the exercise of leadership in the development of management and other employees, innovation and improvement in our business activities and each executive officer’s involvement in industry groups and in the communities that we serve. We seek to compensate executive officers for their performance throughout the year with annual base salaries that are fair and competitive within our marketplace. We believe that executive officer base salaries should be competitive with salaries for executive officers in similar positions and with similar responsibilities in our marketplace and adjusted for financial and operating performance and each executive officer’s performance evaluation, length of service with us and previous work experience. Individual salaries have historically been established by the Compensation Committee based on the general industry knowledge and experience of its members, in alignment with these considerations, to ensure the attraction, development and retention of superior talent. Going forward, we expect that determinations will continue to focus on the above considerations and will also take into account relevant market data, including data from our peer group.

We expect that base salaries will be reviewed annually to ensure continuing consistency with market levels and our level of financial performance during the previous year. Future adjustments to base salaries and salary ranges will reflect movement in the competitive market as well as individual performance. Annual base salary adjustments, if any, for the CEO will be determined by the Compensation Committee. Annual base salary adjustments, if any, for the other executive officers will be determined by the Compensation Committee, taking into account input from the CEO.

On June 9, 2011, we entered into new employment agreements with each of our named executive officers, which agreements will be effective upon the completion of our initial public offering. In connection with approving the new employment agreements, the Compensation Committee approved base salary increases for 2011 for the named executive officers as provided in the table below. The new employment agreements are filed as exhibits to the registration statement of which this prospectus is a part.


					New Base Salary
	Base Salary at the				After Completion of
Name	Beginning of 2011		Base Salary Increase		the Offering

Brian F. Bierbach	$	235,000	$	40,000	$	275,000
Sandra M. Flower	$	140,000	$	35,000	$	175,000
Marty W. Patterson	$	190,000	$	30,000	$	220,000
John J. Connor II	$	185,000	$	35,000	$	220,000
William B. Mathews	$	185,000	$	30,000	$	215,000

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Annual Incentive Bonuses

As one way of accomplishing compensation objectives, executive officers are rewarded for their contribution to our financial and operational success through the award of discretionary annual cash incentive bonuses. Annual cash incentive awards, if any, for the CEO are determined by the Compensation Committee. Annual cash incentive awards, if any, for the other executive officers are determined by the Compensation Committee taking into account input from the CEO.

We expect to review annual cash bonus awards for the named executive officers annually to determine award payments for the prior fiscal year, as well as to establish target bonus amounts for the current fiscal year. At the beginning of each year, the Compensation Committee meets with the CEO to discuss partnership and individual goals for the year and what each executive is expected to contribute in order to help the partnership achieve those goals. However, the amounts of the annual bonuses have been determined in the discretion of the Compensation Committee.

While target bonuses for our executive officers who have entered into employment agreements have been initially set at dollar amounts that are 25% to 100% of their base salaries, the Compensation Committee has had broad discretion to retain, reduce or increase the award amounts when making its final bonus determinations. Target bonus amounts for 2010 for Messrs. Bierbach, Patterson and Connor, which are specified in their existing employment agreements, are set forth in the table below. Please refer to “— Existing Employment Agreements with Named Executive Officers” below for a description of these existing employment agreements. Ms. Flower and Mr. Mathews did not have specific target bonus amounts established for 2010. Further, bonuses (similar to other elements of the compensation provided to executive officers) historically have not been solely based on a prescribed formula or pre-determined goals or specified performance targets but rather have been determined on a discretionary basis and generally have been based on a subjective evaluation of individual, company-wide and industry performances. Target bonus amounts for 2011 for all of the executive officers, which are specified in their new employment agreements, are set forth in the table below. Please refer to “— New Employment Agreements with Named Executive Officers” below for a description of the new employment agreements.

The Board and the Compensation Committee believed that this approach to assessing performance resulted in a more comprehensive evaluation for compensation decisions. In 2010, the Compensation Committee recognized the following factors in making discretionary annual bonus recommendations and determinations:


	•	a subjective performance evaluation based on company-wide financial and individual qualitative performance, as determined in the Compensation Committee’s discretion; and

	•	the scope, level of expertise and experience required for the executive officer’s position.

These factors were selected as the most appropriate measures upon which to base the annual incentive cash bonus decisions because our Compensation Committee believed that they help to align individual compensation with performance and contribution. With respect to its evaluation of company-wide financial performance, although no pre-determined numerical goals are established, the Compensation Committee generally reviewed our results with respect to adjusted EBITDA and cash available for distribution in making annual bonus determinations.

Following its performance assessment, and based on our financial performance with respect to these criteria and the Compensation Committee’s qualitative assessment of individual performance, the Compensation Committee determined to award the incentive bonus amounts set forth in the table below to our named executive officers for performance in 2010.

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	2010 Target		2010 Bonus
Name	Bonus		Awarded

Brian F. Bierbach		$ 65,000	$	65,000
Sandra M. Flower		N/A	$	35,000
Marty W. Patterson		$ 35,000	$	35,000
John J. Connor		$ 40,000	$	50,000
William B. Mathews		N/A	$	35,000

Bonus amounts were awarded based on our financial performance with respect to these criteria and the Compensation Committee’s qualitative assessment of individual performance. Mr. Connor was awarded in excess of his target bonus in recognition of exceptional performance in the areas of control of operational costs and execution of capital projects.

Beginning in 2011, the Compensation Committee expects that it will base annual incentive compensation award recommendations on additional company-wide criteria as well as industry criteria, recognizing the following factors as part of its determination of annual incentive bonuses (without assigning any particular weighting to any factor):


	•	financial performance for the prior fiscal year, including adjusted EBITDA and cash available for distribution;

	•	distribution performance for the prior fiscal year compared to the peer group;

	•	unitholder total return for the prior fiscal year compared to the peer group; and

	•	competitive compensation data of executive officers in the peer group.

These factors were selected as the most appropriate measures upon which to base the annual cash incentive bonus decisions going forward because the Compensation Committee believes that they will most directly correlate to increases in long-term value for our unitholders.

In June 2011, the Compensation Committee established the 2011 target bonus amounts for the named executive officers as provided in the table below.


Name	2010 Target Bonus		Target Bonus Increase		2011 Target Bonus

Brian F. Bierbach	$	65,000	$	210,000	$	275,000
Sandra M. Flower		N/A		N/A	$	100,000
Marty W. Patterson	$	35,000	$	95,000	$	130,000
John J. Connor II	$	40,000	$	90,000	$	130,000
William B. Mathews		N/A		N/A	$	100,000

Equity-Based Awards

Design. The LTIP was adopted in 2009 in connection with our formation. In adopting the LTIP, the Board recognized that it needed a source of equity to attract new members to and retain members of the management team, as well as to provide an equity incentive to other key employees and non-employee directors. We believe the LTIP promotes a long-term focus on results and aligns executive and unitholder interests. Historically, we have granted phantom units with associated DERs to provide long-term incentives to our named executive officers. DERs enable the recipients of phantom unit awards to receive cash distributions on our phantom units to the same extent generally as unitholders receive cash distributions on our common units.

The LTIP is designed to encourage responsible and profitable growth while taking into account non-routine factors that may be integral to our success. Long-term incentive compensation in the form of equity grants are used to provide incentives for performance that leads to enhanced unitholder value, encourage retention and closely align the executive officers’ interests with unitholders’ interests. Equity grants provide a

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vital link between the long-term results achieved for our unitholders and the rewards provided to executive officers and other key employees.

Phantom Units. The only awards made under the LTIP since its adoption have been phantom units. A phantom unit is a notional unit granted under the LTIP that entitles the holder to receive an amount of cash equal to the fair market value of one common unit upon vesting of the phantom unit, unless the Board elects to pay such vested phantom unit with a common unit in lieu of cash. Historically, our Board has always issued common units instead of cash. Unless an individual award agreement provides otherwise, the LTIP provides that unvested phantom units are forfeited at the time the holder terminates employment or board membership, as applicable. The terms of the award agreements of our named executive officers provide that a termination due to death or disability results in full acceleration of vesting. In general, phantom units awarded under our LTIP vest as to 25% of the award on each of the first four anniversaries of the date of grant. A grant of phantom units may include accompanying DERs, which entitle the grantee to receive a cash payment with respect to each phantom unit equal to the cash distribution made by the partnership on each common unit. Under the terms of the award agreements, the phantom units granted to the named executive officers include DERs that are paid to the executive within 10 business days after the date of the associated cash distribution made by the partnership with respect to its common units.

Equity-Based Award Policies. Prior to 2011, equity-based awards were granted by the Compensation Committee in connection with our formation. Going forward, we expect that equity-based awards will be awarded by the Compensation Committee on an annual basis as part of the ongoing total annual compensation package for executive officers. On March 2, 2010, Ms. Flower and Mr. Mathews received awards of 51,579 phantom units and 25,789 phantom units, respectively, including accompanying DERs, in connection with our formation. No other named executive officers received any awards under the LTIP in 2010.

Deferred Compensation

Tax-qualified retirement plans are a common way that companies assist employees in preparing for retirement. We provide our eligible executive officers and other employees with an opportunity to save for their retirement by participating in our 401(k) savings plan. The 401(k) plan allows executive officers and other employees to defer compensation (up to IRS imposed limits) for retirement and permits us to make annual discretionary matching contributions to the plan. For 2010, we matched employee contributions to 401(k) plan accounts up to a maximum employer contribution of 6% of the employee’s eligible compensation. Decisions regarding this element of compensation do not impact any other element of compensation.

Other Benefits

Each of the named executive officers is eligible to participate in our employee benefit plans which provide for medical, dental, vision, disability insurance and life insurance benefits, which are provided on the same terms as available generally to all salaried employees. In 2010, no perquisites were provided to the named executive officers.

Recoupment Policy

We currently do not have a recoupment policy applicable to annual incentive bonuses or equity awards. The Compensation Committee expects to continue to evaluate the need to adopt such a policy, in light of current legislative policies as well as economic and market conditions.

Employment and Severance Arrangements

The Board and the Compensation Committee consider the maintenance of a sound management team to be essential to protecting and enhancing our best interests. To that end, we recognize that the uncertainty that may exist among management with respect to their “at-will” employment with our general partner may result in the departure or distraction of management personnel to our detriment. Accordingly, our general partner previously entered into employment agreements with each of Messrs. Bierbach, Patterson and Connor, which existing employment agreements contain severance arrangements that we believed were appropriate to encourage the continued attention and dedication of members of our management. These employment

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agreements are described more fully below under “— Existing Employment Agreements with Named Executive Officers.” In connection with the initial public offering, on June 9, 2011, our general partner entered into new employment agreements with each of our named executive officers to be effective upon the closing of the offering. These new employment agreements are described more fully under “— New Employment Agreements with Named Executive Officers” below.

Summary Compensation Table for 2010

The following table sets forth certain information with respect to the compensation paid to the named executive officers for the year ended December 31, 2010.


							All Other
Name and Principal Position	Salary		Bonus		Unit Awards(1)		Compensation(2)		Total

Brian F. Bierbach	$	235,000	$	65,000	$	—	$	183,016	$	483,016
President and Chief Executive Officer
Sandra M. Flower	$	140,000	$	35,000	$	643,691	$	7,437	$	826,128
Vice President of Finance
Marty W. Patterson	$	190,000	$	35,000	$	—	$	91,733	$	316,733
Senior Vice President of Commercial Services
John J. Connor II	$	185,000	$	50,000	$	—	$	91,717	$	326,717
Senior Vice President of Operations and Engineering
William B. Mathews	$	185,000	$	35,000	$	321,839	$	9,872	$	581,711
Vice President Legal Affairs, General Counsel and Secretary


(1)		Amounts shown in this column do not reflect dollar amounts actually received by our named executive officers. Instead, these amounts reflect the aggregate grant date fair value of each phantom unit award granted in the year ended December 31, 2010 computed in accordance with the provisions of Financial Accounting Standards Board Accounting Standards Codification Topic 718, Compensation — Stock Compensation (“FASB ASC Topic 718”). Assumptions used in the calculation of these amounts are included in Note 14 to our audited consolidated financial statements included in this prospectus.

(2)		Amounts shown in this column include employer contributions to the named executive officers’ 401(k) plan accounts and life insurance premiums paid by the employer. In addition, the amounts shown for Messrs. Bierbach, Patterson and Connor include the dollar value of any distributions paid on their phantom unit awards pursuant to the DERs in 2010 in the amounts of $182,283, $91,140 and $91,140, respectively. The amounts of such distributions pursuant to DERs are not included in the amounts shown for Ms. Flower and Mr. Mathews because the grant date fair value of their awards reported in the “Unit Awards” column factors in the value of such distributions pursuant to the DERs.

Grants of Plan-Based Awards for 2010

The following table provides information regarding grants of plan-based awards received by Sandra Flower and William Mathews in 2010. Such awards consisted of phantom units and accompanying DERs granted under the LTIP. No other named executive officers received grants of plan-based awards during the year ended December 31, 2010.


		All Other Unit			Grant Date Fair
		Awards: Number of			Value of Phantom
Name	Grant Date	Phantom Units(1)			Unit Awards(2)

Sandra M. Flower	March 2, 2010		51,579	(3)	$	643,691
William B. Mathews	March 2, 2010		25,789	(3)	$	321,839


(1)		Each phantom unit award was accompanied by a DER.

(2)		The grant date fair value of each phantom unit award is computed in accordance with FASB ASC Topic 718, and factors in the value of the DERs accompanying such awards. Assumptions used in the calculation of these amounts are included in Note 14 to our audited consolidated financial statements included in this prospectus.

(3)		Vests as to 25% of the award on each of first four anniversaries of the date of grant.

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Existing Employment Agreements with Named Executive Officers

Our general partner has entered into employment agreements dated November 2, 2009 and effective as of November 4, 2009, with each of Brian F. Bierbach, Marty W. Patterson and John J. Connor. In addition, our general partner has entered into new employment agreements to be effective upon the closing of this initial public offering, with each of the named executive officers, which will replace the existing agreements. Please refer to “— New Employment Agreements with Named Executive Officers” below for a description of the new employment agreements. Each of the existing employment agreements has an initial term of two years. These employment agreements are each automatically extended for successive one-year periods unless and until either party elects to terminate the agreement by giving at least 90 days written notice prior to the commencement of the next succeeding one-year period. These employment agreements will terminate if either party gives such required notice, in which case employment may continue on an “at-will” basis, but the non-compete, non-solicitation and certain other provisions of the agreements would terminate. The base salary and target bonus amounts set forth in such employment agreements are shown in the table below. The employment agreements provide that the base salary may be increased but not decreased (except for a decrease that is consistent with reductions taken generally by other executives of the general partner) and that the executive is eligible to receive an annual cash bonus as approved from time to time by the Compensation Committee based on criteria established by the Compensation Committee. The employment agreements also provide that the executive is eligible to receive awards under the LTIP as determined by the Compensation Committee.


	2010 Base		2010 Target
Name	Salary		Bonus

Brian F. Bierbach	$	235,000	$	65,000
Marty W. Patterson	$	190,000	$	35,000
John J. Connor II	$	185,000	$	40,000

These employment agreements also provide for, among other things, the payment of severance benefits under certain circumstances. Please refer to “— Potential Payment Upon Termination or Change in Control — Employment Agreements with Named Executive Officers” below for a description of these benefits under the employment agreements.

New Employment Agreements with Named Executive Officers

In June 2011, our general partner entered into new employment agreements with each of our named executive officers, which will be effective as of the closing of this offering. Each of the new employment agreements has an initial term of two years, which will be automatically extended for successive one year terms until either party elects to terminate the agreement by giving written notice at least 90 days prior to the end of the expiration of the initial or extended term, as applicable. The base salary and target bonus amounts set forth in such employment agreements are shown in the table below. The employment agreements provide that the base salary may be increased but not decreased (except for a decrease that is consistent with reductions taken generally by other executives of the general partner). The agreements provide that the executive will be provided with the opportunity to earn an annual cash bonus, 20 percent of which will be conditioned and determined on the attainment of personal performance goals and 80 percent of which will be conditioned and determined on the attainment of organizational performance goals, in each case as set by, and based on performance criteria established by, the Compensation Committee. The employment agreements also provide that the executive is eligible to receive awards under the LTIP as determined by the Compensation Committee.

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	Base Salary
Name	following completion of the offering		2011 Target Bonus

Brian F. Bierbach	$	275,000	$	275,000
Sandra M. Flower	$	175,000	$	100,000
Marty W. Patterson	$	220,000	$	130,000
John J. Connor II	$	220,000	$	130,000
William B. Mathews	$	215,000	$	100,000

The new employment agreements also provide for, among other things, the payment of severance benefits under certain circumstances. Please refer to “— Potential Payment Upon Termination or Change in Control — New Employment Agreements with Named Executive Officers” below for a description of these benefits under the new employment agreements.

Outstanding Equity-Based Awards at December 31, 2010

The following table provides information regarding outstanding equity-based awards held by the named executive officers as of December 31, 2010. All such equity-based awards consist of phantom units and accompanying DERs granted under the LTIP.


	Units Awards
	Number of Phantom		Market Value of
	Units That Have Not		Phantom Units That
Name	Vested(1)		Have Not Vested(2)

Brian F. Bierbach		116,053	$	1,586,441
Sandra M. Flower		51,579	$	705,085
Marty W. Patterson		58,026	$	793,215
John J. Connor II		58,026	$	793,215
William B. Mathews		25,789	$	352,536


(1)		The awards to Messrs. Bierbach, Patterson and Connor were granted on November 2, 2009. The awards to Ms. Flower and Mr. Mathews were awarded on March 2, 2010. Each of the awards vests as to 25% of the award on each of the first four anniversaries of the date of grant.

(2)		The market value of phantom units that had not vested as of December 31, 2010 is calculated based on the fair market value of our common units as of December 31, 2010, which was $13.67 multiplied by the number of unvested phantom units. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Equity-Based Awards.”

Units Vested in 2010

The following table shows the phantom unit awards that vested during 2010.


	Number of Units		Value Realized on
Name	Acquired on Vesting		Vesting(1)

Brian F. Bierbach		38,684	$	386,840
Marty W. Patterson		19,342	$	193,420
John J. Connor II		19,342	$	193,420

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(1)		The value realized upon vesting of phantom units is calculated based on the fair market value of our common units as of the applicable vesting date, which was $10.00, multiplied by the number of phantom units that vested.

Long-Term Incentive Plan

The Board has adopted our LTIP for employees, consultants and directors of our general partner and affiliates who perform services for us. The plan provides for the issuance of options, unit appreciation rights, restricted units, phantom units, other unit-based awards, unit awards or replacement awards, as well as tandem DERs granted with respect to an award. To date, only phantom units and related DERs have been issued under the LTIP.

As of June 27, 2011, on a pro forma basis after giving effect to the recapitalization transactions, 209,824 unvested phantom units are outstanding under our LTIP. A phantom unit is a notional unit granted under the LTIP that entitles the holder to receive an amount of cash equal to the fair market value of one common unit upon vesting of the phantom unit, unless the Board elects to pay such vested phantom unit with a common unit in lieu of cash. Historically, our Board has always issued common units in lieu of cash upon vesting of a phantom unit. DERs may be granted in tandem with phantom units. Except as otherwise provided in an award agreement, DERs that are not subject to a restricted period are currently paid to the participant at the time a distribution is made to the unitholders, and DERs that are subject to a restricted period are paid to the participant in a single lump sum no later than the 15th day of the third calendar month following the date on which the restricted period ends.

The number of units that may be delivered with respect to awards under the LTIP may not exceed 625,532 units, subject to specified anti-dilution adjustments. However, if any award is terminated, cancelled, forfeited or expires for any reason without the actual delivery of units covered by such award or units are withheld from an award to satisfy the exercise price or the employer’s tax withholding obligation with respect to such award, such units will again be available for issuance pursuant to other awards granted under the LTIP. In addition, any units allocated to an award will, to the extent such award is paid in cash, be again available for delivery under the LTIP with respect to other awards. There is no limitation on the number of awards that may be granted under the LTIP and paid in cash. The LTIP provides that it is to be administered by the Board, provided that the Board may delegate authority to administer the LTIP to a committee of non-employee directors.

The LTIP may be terminated or amended at any time, including increasing the number of units that may be granted, subject to unitholder approval as required by the securities exchange on which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant. The plan will terminate on the earliest of (i) its termination by the Board or the Compensation Committee, (ii) the tenth anniversary of the date the LTIP was adopted or (iii) when units are no longer available for delivery pursuant to awards under the LTIP. Unless expressly provided for in the plan or an applicable award agreement, any award granted prior to the termination of the plan, and the authority of the Board or the Compensation Committee to amend, adjust or terminate such award or to waive any conditions or rights under such award, will extend beyond the termination date.

Potential Payments Upon Termination or Change in Control

Employment Agreements with Named Executive Officers

The employment agreements with Messrs. Bierbach, Patterson and Connor provide for, among other things, the payment of severance benefits following certain terminations of employment by our general partner or the termination of employment for “Good Reason” (as defined in each of the employment agreements) by the executive officer. Under these agreements, if the executive’s employment is terminated by the general partner other than for “Cause” (as defined in the employment agreements) or other than upon the executive’s death or disability, or if the executive resigns for Good Reason, in each case, during the term of the

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agreement, the executive will have the right to a lump sum cash payment by our general partner equal to the executive’s annual base salary at the rate in effect on the date of such termination, which will be subject to reimbursement by us to our general partner. The foregoing severance benefit is conditioned on the executive executing a release of claims in favor of our general partner and its affiliates, including us.

“Cause” is defined in each employment agreement as the executive having (i) engaged in gross negligence, gross incompetence or willful misconduct in the performance of the duties required of him under the employment agreement, (ii) refused without proper reason to perform the duties and responsibilities required of him under the employment agreement, (iii) willfully engaged in conduct that is materially injurious to our general partner or its affiliates including us (monetarily or otherwise), (iv) committed an act of fraud, embezzlement or willful breach of fiduciary duty to our general partner or an affiliate including us (including the unauthorized disclosure of confidential or proprietary material information of our general partner or an affiliate including us) or (v) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony. “Good Reason” is defined in each employment agreement as a termination by the executive in connection with or based upon (i) a material diminution in the executive’s responsibilities, duties or authority, (ii) a material diminution in the executive’s base compensation, (iii) assignment of the executive to a principal office located beyond a 50-mile radius of the executive’s then current work place, or (iv) a material breach by us of any material provision of the employment agreement.

Phantom Unit Award Agreements

Each of our named executive officers has received an award of phantom units under the LTIP. The terms of the phantom unit award agreements of our named executive officers provide that a termination due to death or disability results in full acceleration of vesting of any outstanding phantom units.

The following table shows the value of the severance benefits and other benefits (1) under the existing employment agreements for the named executive officers who have existing employment agreements and (2) under the phantom unit award agreements, assuming in each case that such named executive officer had terminated employment on December 31, 2010. The named executive officers are not entitled to receive any severance or other benefits upon a change of control under such agreements.

Death or

Termination

Resignation for

Name

Benefit Type

Disability(1)

Without Cause

Good Reason

Brian F. Bierbach

Lump sum payment per employment agreement

None

235,000

Accelerated vesting of phantom units per award agreement

1,586,441

None

Sandra M. Flower

Accelerated vesting of phantom units per award agreement

528,814

None

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Death or

Termination

Resignation for

Name

Benefit Type

Disability(1)

Without Cause

Good Reason

Marty W. Patterson

Lump sum payment per employment agreement

None

190,000

Accelerated vesting of phantom units per award agreement

793,215

None

John J. Connor II

Lump sum payment per employment agreement

None

185,000

Accelerated vesting of phantom units per award agreement

793,215

None

William B. Mathews

Accelerated vesting of phantom units per award agreement

264,402

None


(1)		The amounts shown in this column are calculated based on the fair market value of our common units as of December 31, 2010, which we have assumed was $13.67 multiplied by the number of phantom units that would have vested.

The new employment agreements that will be effective upon the completion of this offering also provide for, among other things, the payment of severance benefits following certain terminations of employment by our general partner, the termination of employment for “Good Reason” (as defined under “— Existing Employment Agreements with Named Executive Officers” above) by the executive officer, or, under certain circumstances, upon expiration of the term of the agreement. Under the new employment agreements, if the executive’s employment is terminated upon expiration of the initial or extended term of the agreement by either party upon 90 days’ written notice (with certain exceptions, as described below), if the executive’s employment is terminated by the general partner other than for “Cause” (as defined under “— Existing Employment Agreements with Named Executive Officers” above) or other than upon the executive’s death or disability, or if the executive resigns for Good Reason, the executive will have the right to severance in an amount equal to the sum of the executive’s annual base salary at the rate in effect on the date of termination plus the amount, if any, paid to the executive as an annual cash bonus for the calendar year ending immediately prior to the date of such termination. Such severance amount will be paid in installments (on regular pay days scheduled in accordance with our regular payroll practices) beginning on the 60th day following the termination date and ending on the one year anniversary of the termination date, and will be subject to reimbursement by us to our general partner. The foregoing severance benefit is conditioned on the executive executing a release of claims in favor of our general partner and its affiliates, including us.

Each employment agreement also contains certain confidentiality covenants prohibiting each executive officer from, among other things, disclosing confidential information relating to our general partner or any of its affiliates, including us. The employment agreements also contain non-competition and non-solicitation restrictions, which apply during the term of the executive’s employment with our general partner and continue for a period of 12 months following termination for any reason. If the executive’s employment is terminated upon expiration of the initial or extended term of the agreement by either party upon 90 days’ written notice, the board of directors may, in its discretion, release the executive from being subject to the noncompetition covenant following termination of employment; however, in that case, the executive would not be entitled to receive any severance payment in connection with such termination.

Amended Phantom Unit Grant Agreements

As discussed above, we do not expect to use DERs as an element of our compensation programs in the future and, on June 9, 2011, we amended each of the outstanding phantom unit grant agreements with our named executive officers to eliminate the DERs previously granted with our phantom units in exchange for a one-time aggregate payment of approximately $1.6 million. The form of the amendment to the phantom unit

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award agreement is filed as an exhibit to the registration statement of which this prospectus forms a part. In addition to eliminating the DERs, the amendments will also provide for acceleration of vesting of phantom units in certain cases in the event of a change of control. More specifically, all unvested phantom units held by a named executive officer will vest:


	•	on the closing date of a Change of Control transaction in which the surviving or acquiring entity does not assume and continue the unvested phantom units on the terms and conditions not less favorable than those provided under the LTIP and the award agreement immediately prior to such Change in Control;

	•	on the closing date of a Change of Control transaction in which the unitholders of the Partnership sell or exchange their interests in the Partnership for consideration comprised entirely of cash or a combination of cash and equity interests in the surviving or acquiring entity, but only with respect to the portion of the then-unvested phantom units equal to the percentage of all the consideration to such unitholders represented by cash;

	•	on the closing date of a Change of Control transaction in which the named executive officer is not offered or does not accept employment with the surviving or acquiring entity; or

	•	on the date of the named executive officer’s termination of employment other than for Cause within one year after the closing date of a Change of Control transaction.

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If the named executive officers terminate employment following the closing of the offering, their terminations would be subject to the terms of their new employment agreements and the amended phantom unit award agreements. The following table shows the value of the severance benefits and other benefits for the named executive officers under the new employment agreements and amended phantom unit grant agreements, assuming the named executive officer terminates employment immediately following the closing of this offering.


				Termination
				Without
				Cause or		Resignation		Certain
		Death or		Upon		For Good		Changes of
Name	Benefit Type	Disability(1)		Expiration(2)		Reason		Control(1)(3)

Brian F. Bierbach	Severance payment per employment agreement		None	$	340,000	$	340,000		None
	Accelerated vesting of phantom unit awards per award agreement	$	1,126,525		None		None	$	1,126,525
Sandra M. Flower	Severance payment per employment agreement		None	$	210,000	$	210,000		None
	Accelerated vesting of phantom unit awards per award agreement	$	375,508		None		None	$	375,508
Marty W. Patterson	Severance payment per employment agreement		None	$	255,000	$	255,000		None
	Accelerated vesting of phantom unit awards per award agreement	$	563,259		None		None	$	563,259
John J. Connor II	Severance payment per employment agreement		None	$	270,000	$	270,000		None
	Accelerated vesting of phantom unit awards per award agreement	$	563,259		None		None	$	563,259
William B. Mathews	Severance payment per employment agreement		None	$	270,000	$	270,000		None
	Accelerated vesting of phantom unit awards per award agreement	$	187,750		None		None	$	187,750


(1)		The amounts shown in this column are calculated based on the fair market value of our common units immediately following the completion of our offering, which we have assumed for this purpose will be $20.00, multiplied by the number of split-adjusted phantom units that would vest.

(2)		In connection with a termination of the executive’s employment upon expiration of the initial or extended term of the agreement by either party pursuant to the terms of the employment agreement, the board of directors may, in its discretion, release the executive from being subject to the noncompetition covenant following termination of employment; however, in such case, the executive would not be entitled to receive the severance payment.

(3)		Pursuant to the amended phantom unit award agreements, accelerated vesting of phantom units would only occur under certain types of change of control transactions, as described under “— Amended Phantom Unit Grant Agreements” above.

Compensation of Directors

In 2010, one of our directors, Kent Moore, received a retainer paid quarterly in cash for his service on the Board. None of our other directors received any fees paid in cash for service on the Board. Following the closing of our initial public offering, we anticipate that each director who is not an officer or employee of our

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general partner will receive compensation for attending meetings of the Board, as well as committee meetings, as follows:


	•	a $50,000 cash retainer;

	•	a $50,000 annual phantom unit grant; and

	•	where applicable, a committee chair retainer of $10,000 for each committee chaired.

In addition, each non-employee director will receive per meeting fees of:


	•	$1,000 for Board meetings attended in person;

	•	where applicable, $500 for Board committee meetings attended in person; and

	•	$500 for telephonic Board meetings and committee meetings greater than one hour in length.

We do not anticipate that Messrs. Moore or Page will participate in the annual phantom unit grant for the foreseeable future because each received a substantial phantom unit grant prior to our initial public offering. We expect Messrs. Moore and Page to receive the other elements of compensation outlined above.

Each non-employee director listed in the table below has received grants of phantom units and accompanying DERs under our LTIP. Each non-employee director is also reimbursed for out-of-pocket expenses in connection with attending meetings of the Board or its committees. Each director will be fully indemnified by us for actions associated with being a director of our general partner to the extent permitted under Delaware law.

In connection with eliminating the use of DERs as an element of our compensation programs in the future, we will amend the outstanding phantom unit award agreements with Messrs. Moore and Page prior to the completion of the offering to eliminate the DERs previously granted with the phantom units. The form of the amendment to the phantom unit award agreement is filed as an exhibit to the registration statement of which this prospectus forms a part. In addition to eliminating the DERs, the amendments will also provide for acceleration of vesting of phantom units in certain cases in the event of a change of control. More specifically, all unvested phantom units held by such directors will vest:


	•	on the closing date of a Change of Control transaction in which the surviving or acquiring entity does not assume and continue the unvested phantom units on the terms and conditions not less favorable than those provided under the LTIP and the award agreement immediately prior to such Change in Control;

	•	on the closing date of a Change of Control transaction in which the unitholders of the Partnership sell or exchange their interests in the Partnership for consideration comprised entirely of cash or a combination of cash and equity interests in the surviving or acquiring entity, but only with respect to the portion of the then-unvested phantom units equal to the percentage of all the consideration to such unitholders represented by cash; or

	•	on the date of the director’s termination of employment, if any, other than for Cause within one year after the closing date of a Change of Control transaction.

Director Compensation Table for 2010

The following table sets forth the compensation paid to our non-employee directors for the year ended December 31, 2010, as described above. The compensation paid in 2010 to Mr. Bierbach as an executive officer is set forth in the Summary Compensation Table above. Mr. Bierbach did not receive any additional compensation related to his service as a director.


	Fees Earned or					All Other
Name and Principal Position	Paid in Cash		Unit Awards(1)			Compensation(2)		Total

L. Kent Moore	$	25,000		—		$	60,760	$	85,760
David L. Page		—	$	623,991	(3)		—	$	623,991

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(1)		The amount reported in this column represents the aggregate grant date fair value of the phantom unit award granted to Mr. Page as computed in accordance with FASB ASC Topic 718, which factors in the value of the accompanying DERs. Assumptions used in the calculation of these amounts are included in Note 14 to our audited consolidated financial statements included in this prospectus.

(2)		The amount reported in this column represents the dollar value of distributions paid in 2010 pursuant to DERs granted in connection with outstanding phantom unit awards held by Mr. Moore. No such amounts are reported with respect to Mr. Page due to the fact that the aggregate grant date fair value of his unit award reported in the above table factors in the value of the accompanying DERs.

(3)		On March 2, 2010, Mr. Page received a grant of 50,000 phantom units, with 25% of such units vesting on each of the first through fourth anniversaries of the grant date. As of December 31, 2010, Mr. Page held an aggregate of 50,000 unvested phantom units.

On November 2, 2009, Mr. Moore received a grant of 51,579 phantom units, with 25% of such units vesting on each of the first through fourth anniversaries of the grant date. As of December 31, 2010, Mr. Moore held an aggregate of 38,684 unvested phantom units. Such phantom units will vest in full upon a change of control.

Compensation Practices as They Relate to Risk Management

We do not believe that our compensation policies and practices create risks that are reasonably likely to have a material adverse effect on the partnership. We believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees). Short-term annual incentives are generally paid pursuant to discretionary bonuses enabling the Compensation Committee to assess the actual behavior of our employees as it relates to risk taking in awarding a bonus. Our use of equity based long-term compensation serves our compensation program’s goal of aligning the interests of executives and unitholders, thereby reducing the incentives to unnecessary risk taking.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding the beneficial ownership of units following the closing of this offering and the related transactions by:


	•	each person who is known to us to beneficially own 5% or more of such units to be outstanding;

	•	our general partner;

	•	each of the directors and named executive officers of our general partner; and

	•	all of the directors and executive officers of our general partner as a group.

All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

Our general partner is owned 100.0% by AIM Midstream Holdings. 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, Brian F. Bierbach, the President and Chief Executive Officer of our general partner and a member of the board of directors of our general partner, Marty W. Patterson, the Vice President of Commercial Affairs of our general partner, John J. Connor II, the Vice President of Operations of our general partner, Sandra M. Flower, the Vice President of Finance of our general partner, and William B. Mathews, the Secretary, General Counsel and Vice President of Legal Affairs of our general partner, have an aggregate 1.1% interest in AIM Midstream Holdings.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of June 9, 2011, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

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The percentage of units beneficially owned is based on a total of 9,052,132 common units and subordinated units outstanding immediately following this offering.


											Percentage of
											Total
			Percentage of					Percentage of			Common and
	Common Units		Common Units			Subordinated		Subordinated Units			Subordinated
	to be		to be			Units to be		to be			Units to be
	Beneficially		Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner	Owned		Owned			Owned		Owned			Owned

AIM Universal Holdings, LLC(1)(2)		725,120		16.0	%		4,526,066		100.0	%		58.0	%
AIM Midstream Holdings, LLC(2)		725,120		16.0	%		4,526,066		100.0	%		58.0	%
Robert B. Hellman, Jr.(2)		—		—	%		—		—	%		—	%
Brian F. Bierbach(3)		*		*	%		—		—	%		*	%
Matthew P. Carbone(2)		—		—	%		—		—	%		—	%
Edward O. Diffendal(2)		—		—	%		—		—	%		—	%
David L. Page(2)		*		*	%		—		—	%		*	%
L. Kent Moore(3)		*		*	%		—		—	%		*	%
Gerald A. Tywoniuk(2)		—		—	%		—		—	%		—	%
Sandra M. Flower(3)		*		*	%		—		—	%		*	%
John J. Connor II(3)		*		*	%		—		—	%		*	%
Marty W. Patterson(3)		*		*	%		—		—	%		*	%
William B. Mathews(3)		*		*	%		—		—	%		*	%
All directors and executive officers as a group (consisting of 10 persons)		59,264		1.3	%		—		—	%		0.7	%


*		An asterisk indicates that the person or entity owns less than one percent.

(1)		AIM Universal Holdings, LLC, a Delaware limited liability company, is the sole manager of AIM Midstream Holdings and may therefore be deemed to beneficially own the 725,120 common units and 4,526,066 subordinated units held by AIM Midstream Holdings. AIM Universal Holdings, LLC’s members consist of Robert B. Hellman, Jr. and Matthew P. Carbone, both directors of our general partner, and George E. McCown.

(2)		The address for this person or entity is 950 Tower Lane, Suite 800, Foster City, California 94404.

(3)		The address for this person or entity is 1614 15th Street, Suite 300, Denver, Colorado 80202.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Immediately following the closing of this offering, AIM Midstream Holdings will own 725,120 common units and 4,526,066 subordinated units, representing a combined 56.9% limited partner interest in us (or 162,620 common units and 4,526,066 subordinated units, representing a combined 50.8% limited partner interest in us, if the underwriters exercise their option to purchase additional common units in full). In addition, AIM Midstream Holdings will own and control our general partner, which will own a 2.0% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of American Midstream Partners, LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Pre-IPO Stage


The consideration received by our general partner and its affiliates prior to or in connection with this offering		• common units; • subordinated units; • all of our incentive distribution rights; and • 2.0% general partner interest.

Post-IPO Stage


Distributions of available cash to our general partner and its affiliates		We will initially make cash distributions 98.0% to our unitholders pro rata, including AIM Midstream Holdings, as the holder of an aggregate of 725,120 common units and 4,526,066 subordinated units, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level.

		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.3 million on its 2.0% general partner interest and AIM Midstream Holdings would receive an annual distribution of approximately $8.7 million on its common units and subordinated units.

Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of us. However, we will 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.

Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units,

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		in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of Our General Partner.”

Liquidation Stage


Liquidation		Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Ownership Interests of Certain Executive Officers and Directors of Our General Partner

Upon the closing of this offering, AIM Midstream Holdings will continue to own 100.0% of our general partner. AIM, Eagle River Ventures, LLC, Stockwell Fund II, L.P. and certain of our executive officers own all of the equity interests in AIM Midstream Holdings. In addition, 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 AIM.

In addition to the 2.0% general partner interest in us, our general partner owns the incentive distribution rights, which entitle the holder 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. Upon the closing of this offering, AIM Midstream Holdings will own 725,120 common units and 4,526,066 subordinated units.

Agreements with Affiliates

We and other parties have or will enter into the various documents and agreements with certain of our affiliates, as described in more detail below. These agreements will affect the offering transactions, including the vesting of assets in, and the assumptions of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.

Advisory Services Agreement

In October 2009, our subsidiary, American Midstream, LLC entered into an advisory services agreement with American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C., and American Infrastructure MLP Associates Management, L.L.C., as the advisors. Under this agreement, the advisors perform certain financial and advisory services for American Midstream, LLC. No fees or reimbursements were paid to the advisors during 2009 in respect of this agreement. During 2010, American Midstream, LLC paid the advisors $250,000 for such services and reimbursed the advisors $77,606 for the advisors’ actual and direct out-of-pocket expenses incurred in the performance of their services. For the calendar year 2011 and each calendar year thereafter, the advisors are entitled to annual compensation in the amount of $250,000, plus a fee determined by a formula that takes into account the increase in gross revenue of American Midstream, LLC over the prior year. American Midstream, LLC is also obligated to reimburse the advisors for their actual and direct out-of-pocket expenses. In connection with the closing of this offering, the advisory services agreement will be terminated in exchange for an aggregate payment of $2.5 million from us to the advisors.

Contribution Agreements

In October 2009, a contribution and sale agreement was entered into by AIM Midstream Holdings and AIM Midstream, LLC, American Infrastructure MLP Fund, L.P., American Infrastructure MLP Private Equity Fund, L.P., American Infrastructure MLP Associates Fund, L.P., Brian F. Bierbach, Marty W. Patterson, John J. Connor II, Eagle River Ventures, LLC, and Stockwell Fund II, L.P., as investors, and AIM Universal Holdings, LLC. Pursuant to this agreement, the investors contributed an aggregate of $100 million to AIM Midstream Holdings in exchange for membership interests in AIM Midstream Holdings.

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In November 2009, we entered into a contribution, conveyance and assumption agreement with AIM Midstream Holdings, American Midstream GP, American Midstream, LLC, and American Midstream Marketing, LLC. Pursuant to this Agreement, AIM Midstream Holdings contributed $2 million to American Midstream GP in exchange for all of the outstanding membership interests in American Midstream GP. American Midstream GP, in turn, contributed such $2 million to us in exchange for 200,000 general partner units representing a 2% general partner interest in us, and all of our incentive distribution rights. AIM Midstream Holdings also contributed $98 million to us in exchange for 9,800,000 common units representing a 98% limited partner interest in us. We then contributed the $100 million that we received from American Midstream GP and AIM Midstream Holdings to American Midstream, LLC in exchange for the continuation of our 100% member interest in American Midstream, LLC.

In September 2010, a contribution and sale agreement was entered into by AIM Midstream Holdings and AIM Midstream, LLC, American Infrastructure MLP Fund, L.P., American Midstream MLP Associates Fund, L.P., American Infrastructure MLP Private Equity Fund, L.P., Eagle River Ventures, LLC, Stockwell Fund II, L.P., John J. Connor II, William B. Mathews, and Sandra M. Flower, as investors. Pursuant to this agreement, the investors contributed an aggregate of $12 million to AIM Midstream Holdings in exchange for membership interests in AIM Midstream Holdings.

In September 2010, we entered into a contribution agreement with AIM Midstream Holdings, our general partner, and American Midstream, LLC. Pursuant to this Agreement, AIM Midstream Holdings contributed $240,000, or 2% of the $12 million contributed by the investors to AIM Midstream Holdings pursuant to the contribution and sale agreement described in the preceding paragraph, to our general partner. Our general partner, in turn, contributed such $240,000 to us in exchange for 24,000 general partner units. AIM Midstream Holdings also contributed $11,760,000, or 98% of the $12 million contributed by the investors to AIM Midstream Holdings pursuant to the contribution and sale agreement described in the preceding paragraph, to us in exchange for 1,176,000 common units. We then contributed the $12 million that we received from American Midstream GP and AIM Midstream Holdings to American Midstream, LLC in furtherance of our existing limited liability company interest American Midstream, LLC.

Procedures for Review, Approval and Ratification of Related-Person Transactions

The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will periodically review all related-person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related-person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics will provide that, in determining whether to recommend the initial approval or ratification of a related-person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on director independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including AIM Midstream Holdings), on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.

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 the resolution of the conflict is:


	•	approved by the Conflicts Committee, although our general partner is not obligated to seek such approval;

	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

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

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

Our general partner may, but is not required to, seek the approval of such resolution from the Conflicts Committee. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to have an honest belief that he is acting in, or not opposed to, the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

AIM Midstream Holdings and other affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, certain affiliates of our general partner, including AIM Midstream Holdings, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Additionally, AIM, through its investment funds and managed accounts, makes investments and purchases entities in various areas of the energy sector, including the midstream natural gas industry. These investments and acquisitions may include entities or assets that we would have been interested in acquiring.

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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors and AIM Midstream Holdings. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, AIM Midstream Holdings may compete with us for investment opportunities and may own an interest in entities that compete with 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.

Our partnership agreement contains provisions that 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. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of our general partner’s limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

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

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duty. For example, our partnership agreement:


	•	provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith, which means the honest belief that the decision is in our best interest;

	•	provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee and not involving a vote of unitholders must either be (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2) “fair and reasonable” to us, as determined by our general partner in good faith, provided that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

	•	provides that our general partner and its executive officers and directors will not be liable for monetary damages to us or our limited partners 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 executive officers or directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that their conduct was criminal.

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought

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Conflicts Committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:


	•	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

	•	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

	•	the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;

	•	the distribution of our cash;

	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	•	the maintenance of insurance for our benefit and the benefit of our partners;

	•	the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;

	•	the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;

	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;

	•	the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

	•	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in “good faith,” our general partner must have an honest belief that the determination is in our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:


	•	the amount and timing of asset purchases and sales;

	•	cash expenditures and the amount of estimated reserve replacement expenditures;

	•	borrowings;

	•	the issuance of additional units; and

	•	the creation, reduction or increase of reserves in any quarter.

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

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amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $11.5 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:


	•	enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

	•	hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.

We will reimburse our general partner and its affiliates for expenses.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. The fully allocated basis charged by our general partner does not include a profit component. Please read “Certain Relationships and Related Party Transactions.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the Conflicts Committee may make a determination on our behalf with respect to such arrangements.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the close of this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

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

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any

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affiliate of our general partner or its assets. 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 terms that are more favorable without the limitation on liability.

Common units are subject to our general partner’s limited call right.

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the Conflicts Committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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 or our unitholders. This election may result in lower distributions to our public common unitholders in certain situations.

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

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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 — Distributions of Available Cash — General Partner Interest and Incentive Distribution Rights.”

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify or eliminate, except for the contractual covenant of good faith and fair dealing, the fiduciary duties owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. Without such modifications, such transactions could result in violations of our general partner’s state-law fiduciary duty standards. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our general partner in a manner beneficial both to its owners, as well as to our unitholders. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration the interests of all parties involved, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:


State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or our limited partners whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

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		Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders or that are not approved by the Conflicts Committee must be:

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

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

		If our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, 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. These standards reduce the obligations to which our general partner would otherwise be held.

		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors 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 unlawful.

Rights and remedies of unitholders		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

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Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons 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 unlawful. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

Computershare Trust Company, N.A. will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by our unitholders:


	•	surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;

	•	special charges for services requested by a holder of a common unit; and

	•	other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:


	•	automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;

	•	represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and

	•	gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with this offering.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:


	•	with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions;”

	•	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties;”

	•	with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units;” and

	•	with regard to allocations of taxable income and taxable loss, please read “Material Federal Income Tax Consequences.”

Organization and Duration

We were organized in August 2009 and have a perpetual existence.

Purpose

Our purpose under our partnership agreement is limited to any business activities that are approved by our general partner and in any event that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the power to cause us, our operating company and its subsidiaries to engage in activities other than the business of gathering, compressing, treating and transporting natural gas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

For a discussion of our general partner’s right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read “— Issuance of Additional Securities.”

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Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a “unit majority” require:


	•	during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

	•	after the subordination period, the approval of a majority of the outstanding common units.

By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us and our limited partners.



Issuance of additional units		No approval right.

Amendment of our partnership agreement		Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of Our Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read “— Merger, Sale or Other Disposition of Assets.”

Dissolution of our partnership		Unit majority. Please read “— Termination and Dissolution.”

Continuation of our business upon dissolution		Unit majority. Please read “— Termination and Dissolution.”

Withdrawal of our general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2021 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of Our General Partner.”

Removal of our general partner		Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner.”

Transfer of our general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger, consolidation or conversion with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to June 30, 2020. Please read “— Transfer of General Partner Interest.”

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Transfer of incentive distribution rights		No approval right. Please read “— Transfer of Subordinated Units and Incentive Distribution Rights.”

Transfer of ownership interests in our general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in Our General Partner.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group:


	•	to remove or replace our general partner;

	•	to approve some amendments to our partnership agreement; or

	•	to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business primarily in five states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a

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manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our limited partners.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.

Upon issuance of additional partnership securities, our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner’s 2.0% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership securities.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:


	•	enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

	•	enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

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The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon the closing of this offering, affiliates of our general partner will own approximately 58.0% of the outstanding common and subordinated units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:


	•	a change in our name, the location of our principal place of business, our registered agent or our registered office;

	•	the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

	•	a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, our operating company, nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	•	a change in our fiscal year or taxable period and related changes;

	•	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

	•	an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

	•	any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;

	•	mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or

	•	any other amendments substantially similar to any of the matters described above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:


	•	do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

	•	are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

	•	are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the units are or will be listed for trading;

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	•	are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

	•	are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Limited Partner Approval

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under “— No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or our limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries’ assets in a single transaction or a series of related transactions, including by way of merger, consolidation, other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our and our subsidiaries’ assets without that approval. Our general partner may also sell all or substantially all of our and our subsidiaries’ assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of the limited partners), each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20.0% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed limited liability entity, if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a merger, consolidation or conversion, a sale of substantially all of our assets or any other similar transaction or event.

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Termination and Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:


	•	the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following the approval and admission of a successor general partner;

	•	the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

	•	the entry of a decree of judicial dissolution of our partnership; or

	•	there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement and appoint as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:


	•	the action would not result in the loss of limited liability of any limited partner; and

	•	neither we nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time if it determines that an immediate sale or distribution would be impractical or would cause undue loss to our partners. The liquidator may distribute our assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2021 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2021, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving at least 90 days’ advance notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50.0% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest and incentive distribution rights in us without the approval of the unitholders. Please read “— Transfer of General Partner Interest” and “— Transfer of Subordinated Units and Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an

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opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of all outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, and a majority of the outstanding subordinated units, voting as a single class. The ownership of more than 332/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, affiliates of our general partner will own 58.0% of the outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end and all outstanding subordinated units will immediately and automatically convert into common units on a one-for-one basis;

	•	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 based on the fair market value of the interests at the time.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred in connection with the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to:


	•	an affiliate of our general partner (other than an individual); or

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	•	another entity as part of the merger, consolidation or conversion of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity.

our general partner may not transfer all or any of its general partner interest to another person prior to June 30, 2021 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may, at any time, transfer common units or subordinated units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Transfer of Subordinated Units and Incentive Distribution Rights

By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:


	•	represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

	•	automatically becomes bound by the terms and conditions of our partnership agreement; and

	•	gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Subordinated units or incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

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	•	the subordination period will end and all outstanding subordinated units will immediately and automatically convert into common units on a one-for-one basis;

	•	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 based on the fair market value of the interests at the time.

Limited Call Right

If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:


	•	the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

	•	the average of the daily closing prices of the partnership securities of such class for the 20 consecutive trading days preceding the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Federal Income Tax Consequences — Disposition of Common Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, unitholders who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

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Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us under Federal Energy Regulatory Commission regulations, or in order to reverse an adverse determination that has occurred regarding such maximum applicable rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, 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 necessary or advisable to:


	•	obtain proof of the U.S. federal income tax status of our member (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. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

A non-taxpaying assignee will not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Non-Taxpaying Assignees; Redemption

In the event any rates that we charge our customers become regulated by the Federal Energy Regulatory Commission, to avoid any adverse effect on the maximum applicable rates chargeable to customers by us, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, 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

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maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:


	•	obtain proof of the U.S. federal income tax status of our member (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. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Indemnification

Under our partnership agreement, we will indemnify the following persons, in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	•	our general partner;

	•	any departing general partner;

	•	any person who is or was an affiliate of our general partner or any departing general partner;

	•	any person who is or was a member, manager, partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

	•	any person who is or was serving at the request of the general partner or any departing general partner as an officer, director, member, manager, partner, fiduciary or trustee of another person; and

	•	any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep or cause to be kept appropriate books and records of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, we use the calendar year.

We will furnish or make available (by posting on our website or other reasonable means) to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants, including a balance sheet and statements of operations, and our equity and cash flows. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

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As soon as practicable, but in no event later than 90 days after the close of each quarter except the last quarter of each fiscal year, our general partner will mail or make available to each record holder of a unit a report containing our unaudited financial statements and such other information as may be required by applicable law, regulation or rule. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable demand and at its own expense, have furnished to him:


	•	a current list of the name and last known business, residence or mailing address of each record holder;

	•	copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments, and powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units, or other partnership securities proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years and for so long thereafter as is required for the holder to sell its partnership securities following any withdrawal or removal of American Midstream GP as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, AIM Midstream Holdings will hold an aggregate of 725,120 common units and 4,526,066 subordinated units (or 162,620 common units and 4,526,066 subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1.0% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates, excluding any individual who is an affiliate of our general partner, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these common units and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.

AIM Midstream Holdings, our general partner and the executive officers and directors of our general partner have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to American Midstream Partners, LP and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, IRAs, real estate investment trusts (REITs) or mutual funds. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Andrews Kurth LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Andrews Kurth LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and other products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 6% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Andrews Kurth LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Andrews Kurth LLP on such matters. It is the opinion of Andrews Kurth LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:


	•	We will be classified as a partnership for federal income tax purposes; and

	•	Each of our operating subsidiaries will be disregarded as an entity separate from us or will be treated as a partnership for federal income tax purposes.

In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Andrews Kurth LLP has relied are:


	•	Neither we nor the operating subsidiaries has elected or will elect to be treated as a corporation; and

	•	For each taxable year, more than 90% of our gross income has been and will be income of the type that Andrews Kurth LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxed as a corporation for federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction

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in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Andrews Kurth LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who are admitted as limited partners of American Midstream Partners, LP will be treated as partners of American Midstream Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of American Midstream Partners, LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in American Midstream Partners, LP. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in American Midstream Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “— Entity-Level Collections,” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, depletion recapture and/or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having

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exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2013, 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 with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:


	•	gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value,” as defined in Treasury Regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon

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the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be

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determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

Andrews Kurth LLP is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

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Treatment of Short Sales

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


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Andrews Kurth LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, 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 modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

Recently enacted legislation will impose a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “— Disposition of Common Units — Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets, or inside basis, under Section 743(b) of the Internal

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Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets, or common basis, and (ii) his Section 743(b) adjustment to that basis.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Units.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” Andrews Kurth LLP is unable to opine as to whether our method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

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The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

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Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2012 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income each year, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common

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units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase

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within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have terminated our tax partnership for federal income tax purposes upon the sale or exchange of our interests that, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method

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to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “— Tax Consequences of Unit Ownership — Section 754 Election,” Andrews Kurth LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

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Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Andrews Kurth LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names American Midstream GP as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	•	the name, address and taxpayer identification number of the beneficial owner and the nominee;

	•	whether the beneficial owner is:


	•	a person that is not a U.S. person;

	•	a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

	•	a tax-exempt entity;


	•	the amount and description of units held, acquired or transferred for the beneficial owner; and

	•	specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

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Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:


	•	for which there is, or was, “substantial authority”; or

	•	as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts.

No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”

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Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties”;

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

Recent Legislative Developments

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. For example, in the last session of Congress, the U.S. House of Representatives passed legislation that would provide for substantive changes to the definition of qualifying income and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these legislative efforts could result in changes to the existing federal income tax laws that affect publicly traded partnerships. As previously proposed, we do not believe any such legislation would affect our tax treatment as a partnership. However, the proposed legislation could be modified in a way that could affect us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business or own property in several states, most of which impose personal income taxes on individuals. Most of these states also impose an income tax on corporations and other entities. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. A unitholder may be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Andrews Kurth LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN AMERICAN MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, “Similar Laws.” For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements, collectively, “Employee Benefit Plans.” Among other things, consideration should be given to:


	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

	•	whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences — Tax-Exempt Organizations and Other Investors;” and

	•	whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the Employee Benefit Plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by the Employee Benefit Plan are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

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(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by “benefit plan investors,” which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by Employee Benefit Plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

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UNDERWRITING

Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are acting as joint book-running managers of the offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.


	Number of
	Common
Underwriter	Units

Citigroup Global Markets Inc.
Merrill Lynch, Pierce, Fenner & Smith Incorporated
Barclays Capital Inc.
Raymond James & Associates, Inc.
Wells Fargo Securities, LLC

Total		3,750,000

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the over-allotment option described below) if they purchase any of the common units.

Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $ per common unit. If all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representatives have advised us that the underwriters do not intend to make sales to discretionary accounts.

If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 562,500 additional common units at the public offering price less underwriting discounts and commissions, and the structuring fee. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

We, our officers and directors, and our other unitholders, including our general partner and AIM Midstream Holdings and its affiliates, have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, dispose of or hedge any common units or any securities convertible into or exchangeable for our common stock. Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated in their sole discretion may release any of the securities subject to these lock-up agreements at any time without notice. Notwithstanding the foregoing, if (i) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our partnership occurs; or (ii) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

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.

213

The following table shows the underwriting discounts, commissions and the structuring fee that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ over-allotment option.


	Paid by American Midstream Partners, LP(1)
	No Exercise	Full Exercise

Per common unit	$	$
Total	$	$


(1)		Excludes a structuring fee of $ million, or $ million if the underwriters exercise their over-allotment option in full, payable by us to Citigroup Global Markets, Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated.

We will pay a structuring fee equal to 0.75% of the gross proceeds of this offering, including the gross proceeds from any exercise of the underwriters’ over-allotment option, to Citigroup Global Markets Inc. and Merrill, Lynch, Pierce, Fenner & Smith Incorporated. This structuring fee will compensate Citigroup Global Markets Inc. and Merrill, Lynch, Pierce, Fenner & Smith Incorporated for providing advice regarding the capital structure of our partnership, the terms of the offering, the terms of our partnership agreement and the terms of certain other agreements between us and our affiliates.

We estimate that our total expenses for this offering will be approximately $3.3 million.

In connection with the offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the over-allotment option, and stabilizing purchases.


	•	Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in the offering.


	•	“Covered” short sales are sales of common units in an amount up to the number of common units represented by the underwriters’ over-allotment option.

	•	“Naked” short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters’ over-allotment option.


	•	Covering transactions involve purchases of common units either pursuant to the over-allotment option or in the open market after the distribution has been completed in order to cover short positions.


	•	To close a naked short position, the underwriters must purchase common units in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

	•	To close a covered short position, the underwriters must purchase common units in the open market after the distribution has been completed or must exercise the over-allotment option. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option.


	•	Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

214

The underwriters have performed commercial banking, investment banking and advisory services for us from time to time for which they have received customary fees and reimbursement of expenses. The underwriters may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. Additionally, affiliates of certain of the underwriters will serve as lenders under our new credit facility.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Because the Financial Industry Regulatory Authority views our common units as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations among us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our partnership. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:


	•	to any legal entity that is a qualified investor as defined in the Prospectus Directive;

	•	to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the Representatives; or

	•	in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the Directive 2010/73/EU, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state, and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of

215

the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in the Dubai International Financial Centre

This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (“DFSA”). This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The shares to which this prospectus relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this prospectus you should consult an authorized financial advisor.

Notice to Prospective Investors in the United Kingdom

Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000, or FSMA, that is not a “recognised collective investment scheme” for the purposes of FSMA, or CIS, and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and are only directed at:

(i) if our partnership is a CIS and is marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the “CIS Promotion Order”) or (b) high net worth companies and other persons falling with Article 22(2)(a) to (d) of the CIS Promotion Order; or

(ii) otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Financial Promotion Order”) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

(iii) in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”). Our partnership’s common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to our partnership.

Notice to Prospective Investors in Germany

This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht-BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to this offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of the common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified

216

investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

This offering of our common units does not constitute an offer to buy or the solicitation or an offer to sell our common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in the Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering.

We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006, or CISA. Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

217

VALIDITY OF THE COMMON UNITS

The validity of the common units offered hereby will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The consolidated financial statements of American Midstream Partners, LP and subsidiaries as of and for the year ended December 31, 2010 and as of December 31, 2009 and for the period from August 20, 2009 to December 31, 2009 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in accounting and auditing.

The combined financial statements of American Midstream Partners Predecessor as of October 31, 2009 and for the ten-month period ended October 31, 2009 and as of and for the year ended December 31, 2008 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered in this prospectus, you may desire to review the full registration statement, including the exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549 at prescribed rates or from the SEC’s web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website is located at http://www.americanmidstream.com, and we expect to make our periodic reports and other information filed with or furnished to the SEC available, 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 into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. Our annual report will contain a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “will,” “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of financial condition or of results of operations, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

218

American Midstream Partners, LP and Subsidiaries

Unaudited Consolidated Balance Sheets

December 31, 2010 and March 31, 2011


					Pro Forma
					March 31,
	December 31,		March 31,		2011
	2010		2011		(note 1)
	(in thousands)

Assets
Current assets
Cash and cash equivalents	$	63	$	153	$	153
Accounts receivable, net		656		1,490		1,490
Unbilled revenue		22,194		20,758		20,758
Risk management assets		—		174		174
Other current assets		1,523		1,948		1,948

Total current assets		24,436		24,523		24,523

Property, plant and equipment, net		146,808		143,394		143,394
Other assets		1,985		1,776		1,776

Total assets	$	173,229	$	169,693	$	169,693

Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	980	$	1,105	$	1,105
Accrued gas purchases		18,706		17,599		17,599
Dividend payable		—		—		30,000
Current portion of long-term debt		6,000		7,000		7,000
Other loans		615		463		463
Risk management liabilities		—		3,079		3,079
Accrued expenses and other current liabilities		2,676		3,644		3,644

Total current liabilities		28,977		32,890		62,890
Other liabilities		8,078		8,338		8,338
Long-term debt		50,370		49,500		49,500

Total liabilities		87,425		90,728		120,728

Commitments and contingencies (see Note 10)
Partners’ capital
General partner interest (0.2 million units outstanding as of December 31, 2010 and March 31, 2011 and 0.1 million on a pro forma basis as of March 31, 2011)		2,124		1,998		1,404
Limited partner interest (11.0 million and 11.1 million units outstanding as of December 31, 2010 and March 31, 2011, respectively and 0.9 million on a pro forma basis as of March 31, 2011)		83,624		76,911		7,535
Subordinated units (4.5 million outstanding on a pro forma basis as of March 31, 2011)		—		—		39,970
Accumulated other comprehensive income		56		56		56

Total partners’ capital		85,804		78,965		48,965

Total liabilities and partners’ capital	$	173,229	$	169,693	$	169,693

The accompanying notes are an integral part of these consolidated financial statements.

F-2

American Midstream Partners, LP and Subsidiaries

Unaudited Consolidated Statements of Operations

For the Three Months Ended March 31, 2010 and 2011


	Three Months Ended March 31,
	2010			2011
	(in thousands)

Revenue	$	54,712		$	67,265
Unrealized gain (loss) on commodity derivatives		—			(3,500	)
Total revenue		54,712			63,765

Operating expenses:
Purchases of natural gas, NGLs and condensate		44,964			54,953
Direct operating expenses		2,692			3,058
Selling, general and administrative expenses		2,113			2,675
One-time transaction costs		74			288
Depreciation expense		4,966			5,037

Total operating expenses		54,809			66,011

Operating income (loss)		(97	)		(2,246	)
Other expenses (income):
Interest expense		1,357			1,264

Net income (loss)	$	(1,454	)	$	(3,510	)

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

Limited partners’ interest in net income (loss)	$	(1,425	)	$	(3,440	)

Limited partners’ net income (loss) per common unit (See Note 13)	$	(0.14	)	$	(0.30	)

Weighted average number of common units used in computation of limited partners’ net income (loss) per common unit		10,202			11,473

Pro forma earnings per common and subordinated units (See Note 1)				$	(0.61	)
Pro forma weighted average common and subordinated units outstanding (See Note 1)					5,668

The accompanying notes are an integral part of these consolidated financial statements.

F-3

American Midstream Partners, LP and Subsidiaries

Unaudited Consolidated Statements of Changes in Partners’ Capital for the
Three Months Ended March 31, 2010 and March 31, 2011


											Accumulated
	Limited		Limited			General		General			Other
	Partner		Partner			Partner		Partner			Comprehensive
	Units		Interest			Units		Interest			Income		Total
						(in thousands)

Balances at December 31, 2009		9,800	$	91,148			200	$	2,010		$	46	$	93,204
Net income (loss)		—		(1,425	)		—		(29	)		—		(1,454	)
Unit based compensation		—		—			—		254			—		254
Adjustments to other post retirement plan assets and liabilities		—		—			—		—			—		—

Balances at March 31, 2010		9,800	$	89,723			200	$	2,235		$	46	$	92,004

Balances at December 31, 2010		11,049	$	83,624			224	$	2,124		$	56	$	85,804
Net income (loss)		—		(3,440	)		—		(70	)		—		(3,510	)
Unitholder distributions		—		(3,591	)		—		(73	)		—		(3,664	)
LTIP vesting		32		318			—		(318	)		—		—
Unit based compensation		—		—			—		335			—		335
Adjustments to other post retirement benefit plan assets and liabilities		—		—			—		—			—		—

Balances at March 31, 2011		11,081	$	76,911			224	$	1,998		$	56	$	78,965

The accompanying notes are an integral part of these consolidated financial statements.

F-4

American Midstream Partners, LP and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

Three Months Ended March 31, 2010 and 2011


	Three Months Ended March 31,
	2010			2011
	(in thousands)

Cash flows from operating activities
Net income (loss)	$	(1,454	)	$	(3,510	)
Adjustments to reconcile change in net assets to net cash used in operating activities:
Depreciation expense		4,966			5,037
Amortization of deferred financing costs		198			197
Mark to market on derivatives		20			3,500
Unit based compensation		254			335
Changes in operating assets and liabilities:
Accounts receivable		(219	)		(834	)
Unbilled revenue		2,549			1,436
Risk management assets		—			(670	)
Other current assets		(304	)		(425	)
Other assets		(160	)		12
Accounts payable		(1,620	)		125
Accrued gas purchase		(2,482	)		(1,107	)
Accrued expenses and other current liabilities		512			968
Risk management liabilities		—			75
Other liabilities		63			(72	)

Net cash provided (used) in operating activities		2,323			5,067

Cash flows from investing activities
Additions to property, plant and equipment		(494	)		(1,291	)

Net cash used in investing activities		(494	)		(1,291	)

Cash flows from financing activities
Unit holder distributions		—			(3,664	)
Payments on other loan		(268	)		(152	)
Borrowings on long-term debt		2,500			21,300
Payments on long-term debt		(5,120	)		(21,170	)

Net cash provided (used) by financing activities		(2,888	)		(3,686	)

Net increase (decrease) in cash and cash equivalents		(1,059	)		90
Cash and cash equivalents
Beginning of period		1,149			63

End of period	$	90		$	153

Supplemental cash flow information
Interest payments	$	1,198		$	1,054

The accompanying notes are an integral part of these consolidated financial statements.

F-5

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011


1.	Summary of Significant Accounting Policies

Nature of Business

American Midstream Partners, LP (the “Partnership”) was formed on August 20, 2009 (“date of inception”) as a Delaware limited partnership for the purpose of acquiring and operating certain natural gas pipeline and processing businesses. We provide natural gas gathering, treating, processing, marketing and transportation services in the Gulf Coast and Southeast regions of the United States. We hold our assets in a series of wholly owned limited liability companies as well as a limited partnership. Our capital accounts consist of general partner interests and limited partner interests.

We are controlled by our general partner, American Midstream GP, LLC, which is a wholly owned subsidiary of AIM Midstream Holdings, LLC.

Our interstate natural gas pipeline assets transport natural gas through Federal Energy Regulatory Commission (the “FERC”) regulated interstate natural gas pipelines in Louisiana, Mississippi, Alabama and Tennessee. Our interstate pipelines include:


	•	American Midstream (Midla), LLC, which owns and operates approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana.

	•	American Midstream (AlaTenn), LLC, which owns and operates more than approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an eight county area in Alabama, Mississippi and Tennessee.

Basis of Presentation

These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include disclosures required by GAAP for annual periods. The unaudited consolidated financial statements for the three months ended March 31, 2010 and 2011 include all adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods.

Our financial results for the three months ended March 31, 2010 and 2011 are not necessarily indicative of the results that may be expected for the full years ending December 31, 2010 and 2011. These unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this registration statement.

The unaudited pro forma consolidated balance sheet as of March 31, 2001 gives effect to:


	•	the accrual of distributions payable to unitholders of record as of May 27, 2011 and our general partner, in each case in connection with our proposed initial public offering (see Note 14) and as if such distributions had been declared effective as of March 31, 2011; and

	•	the following recapitalization transactions (the “Recapitalization Transactions”) as if they had occurred as of March 31, 2011:


	•	each general partner unit held by our general partner is 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;

F-6

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)


	•	each common unit held by participants in our Long-Term Incentive Plan, or LTIP, is 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 is 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 is 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 are converted into 801,139 common units and 4,526,066 subordinated units.

Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas

We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation, we record those fees separately in revenues. For the three months ended March 31, 2010 and 2011, respectively, the Partnership had the following revenues by category:


	Three Months Ended March 31,
	2010		2011
	(in thousands)

Revenue
Transportation — firm	$	3,376	$	3,318
Transportation — interruptible		666		965
Sales of natural gas, NGLs and condensate		50,660		62,822
Other		10		160
Unrealized losses on commodity derivatives		—		(3,500	)

Total revenue	$	54,712	$	63,765

Limited Partners’ Net Income Per Unit

We compute Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period. The overall computation, presentation and disclosure requirements for our Limited Partners’ Net Income per Unit are made in accordance with the “Earnings per Share” Topic of the Codification.

Pro Forma Earnings Per Common and Subordinated Unit

The pro forma earnings per common and subordinated unit provides supplemental information in connection with our proposed initial public offering (see Note 14). The pro forma earnings per common and subordinated unit is calculated by dividing earnings attributable to common and subordinated units by pro forma units, giving effect to the Recapitalization Transactions as of 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

F-7

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

of the dividend that will be funded from the proceeds of this offering that exceeds net income for the three months ended March 31, 2011.

The following table sets forth a reconciliation between historical weighted average common units used in the computation of limited partners’ equity income (loss) per common unit at March 31, 2011 to the pro forma weighted average common and subordinated units outstanding used in the calculation of pro forma earnings per common and subordinated unit (in thousands of units):


Historical weighted average common units used in the computation of limited partners’ net income (loss) per common unit	11,473
Impact of reverse unit split into 0.485 common units	(5,905	)
Additional number of common units issued in this offering (at an assumed offering price of $20.00) necessary to pay a portion of the distribution to LTIP participants holding common units, AIM Midstream Holdings and our general partner that will be funded from the proceeds of this offering that exceeds net income	100

Pro forma weighted average common and subordinated units outstanding used in the calculation of pro forma earnings per common and subordinated unit	5,668


2.	Acquisition

On October 2, 2009, American Midstream, LLC, a wholly owned subsidiary, entered into a purchase and sale agreement to acquire certain pipeline businesses from Enbridge Midcoast Energy, L.P., for an aggregate purchase price of approximately $150.8 million. The acquisition was effective as of November 1, 2009. Prior to the acquisition, we had no operating tangible assets.

The acquired businesses were renamed as follows:

American Midstream (Alabama Intrastate), LLC

American Midstream (Bamagas Intrastate), LLC

American Midstream (Tennessee River), LLC

American Midstream (Mississippi), LLC

American Midstream (Midla), LLC

American Midstream (Alabama Gathering), LLC

American Midstream (AlaTenn), LLC

American Midstream Onshore Pipelines, LLC

Mid Louisiana Gas Transmission, LLC

American Midstream Offshore (Seacrest), LP

American Midstream (SIGCO Intrastate), LLC

American Midstream (Louisiana Intrastate), LLC

The acquisition qualifies as a business combination and, as such, the Partnership estimated the fair value of each property as of the acquisition date (the date on which the Partnership obtained control of the properties). The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. The Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, expectations for timing and amount of future development and operating costs, projections of future rates of production and risk adjusted discount rates. These assumptions represent Level 3 inputs.

F-8

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

The following table summarizes the consideration paid to the seller and the amounts of the assets acquired and liabilities assumed in the acquisition.


	(in thousands)

Consideration paid to seller
Cash consideration	$	150,818

Recognized amounts of identifiable assets acquired and liabilities assumed
Property, plant and equipment		151,085
Other post-retirement benefit plan assets, net		394
Other liabilities assumed		(661	)

Total identifiable net assets	$	150,818

Acquisition costs of $0.07 million and $0.29 million have been recorded in the statements of operations under the caption Transaction costs on acquisitions for the three months ended March 31, 2010 and 2011, respectively.


3.	Concentration of Credit Risk and Trade Accounts Receivable

Our primary market areas are located in the United States along the Gulf Coast and in the Southeast. We have a concentration of trade receivable balances due from companies engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers’ historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable. For the period and year ended December 31, 2009 and 2010, no allowances on accounts receivable were recorded.

Enbridge Marketing (US) L.P., ConocoPhillips Corporation, ExxonMobil Corporation and Dow Hydrocarbons and Resources were significant customers, representing at least 10% of our consolidated revenue, accounting for $29.5 million, $7.1 million, $0.1 million and $5.7 million, respectively, of our consolidated revenue in the consolidated statement of operations in the three months ended March 31, 2010 and $12.0 million, $28.5 million, $9.6 million and $3.9 million, respectively, for the three months ended March 31, 2011.


4.	Derivatives

Commodity Derivatives

To minimize the effect of a downturn in commodity prices and protect the Partnership’s profitability and the economics of its development plans, the Partnership enters into commodity economic hedge contracts from time to time. The terms of contracts depend on various factors, including management’s view of future commodity prices, acquisition economics on purchased assets and future financial commitments. This hedging program is designed to moderate the effects of a severe commodity price downturn while allowing us to participate in some commodity price increases. Management regularly monitors the commodity markets and financial commitments to determine if, when, and at what level some form of commodity hedging is appropriate in accordance with policies which are established by the board of directors of our general partner. Currently, the commodity hedges are in the form of swaps and puts.

F-9

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

The Partnership is required to post collateral with one counterparty in connection with its derivative positions. As of March 31, 2011, the Partnership had posted $0.68 million in collateral. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with each of the Partnership’s counterparties allowing the Partnership to offset its commodity derivative asset and liability positions.

As of March 31, 2011, the notional volumes of our commodity hedges for 2011 were 10.9 million gallons and 7.5 million gallons for 2012.

Interest Rate Derivatives

The Partnership also utilizes interest rate caps to protect against changes in interest rates on its floating rate debt.

At March 31, 2011, the Partnership had $56.5 million outstanding under its credit facility, with interest accruing at a rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates, the Partnership has entered into interest rate caps that mitigate the risk of increases in interest rates. As of March 31, 2011, we had interest rate caps with a notional amount of $25.0 million that effectively fix the base rate on that portion of our debt, with a fixed maximum rate of 4%.

For accounting purposes, no derivative instruments were designated as hedging instruments and were instead accounted for under the mark-to-market method of accounting, with any changes in the mark-to-market value of the derivatives recorded in the balance sheets and through earnings, rather than being deferred until the anticipated transactions affect earnings. The use of mark-to-market accounting for financial instruments can cause noncash earnings volatility due to changes in the underlying commodity prices indices or interest rates.

As of December 31, 2010 and March 31, 2011, the fair value associated with the Partnership’s derivative instruments were recorded in our financial statements, under the caption Risk management assets and Risk management liabilities, as follows:


	December 31,		March 31,
	2010		2011
	(in thousands)

Risk management assets:
Commodity derivatives	$	—	$	174
Interest rate derivatives		—		—

	$	—	$	174

Risk management liabilities:
Commodity derivatives	$	—	$	3,079
Interest rate derivatives		—		—

	$	—	$	3,079

F-10

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

We recorded the following mark-to-market losses:


	Three Months Ended March 31,
	2010			2011
	(in thousands)

Commodity derivatives	$	—		$	(3,500	)
Interest rate derivatives		(20	)		—

	$	(20	)	$	(3,500	)

Fair Value Measurements

The Partnership’s interest rate caps and commodity derivatives discussed above were classified as Level 3 derivatives for all periods presented.

The table below includes a roll forward of the balance sheet amounts (including the change in fair value) for financial instruments classified by us within Level 3 of the valuation hierarchy. When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources).


	Three Months Ended March 31
	2010			2011
	(in thousands)

Fair value asset (liability), beginning of period	$	77		$	—
Total realized and unrealized (losses) gains included in revenue		(20	)		(3,920	)
Purchases		—			670
Settlements		—			345

Fair value (liability) asset, end of period	$	57		$	(2,905	)


5.	Property, Plant and Equipment, Net

Property, plant and equipment, net, as of December 31, 2010 and March 31, 2011 were as follows:


			December 31,			March 31,
	Useful Life		2010			2011
			(in thousands)

Land			$	41		$	41
Buildings and improvements		4 to 40		2,523			2,527
Processing and treating plants		8 to 40		11,954			11,955
Pipelines		5 to 40		143,805			144,784
Compressors		4 to 20		7,163			7,211
Equipment		8 to 20		1,711			1,966
Computer software		5		1,390			1,393

Total property, plant and equipment				168,587			169,877
Accumulated depreciation				(21,779	)		(26,483	)

Property, plant and equipment, net			$	146,808		$	143,394

F-11

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

Of the gross property, plant and equipment balances at December 31, 2010 and March 31, 2011, $24.3 million relate to regulated assets.


6.	Asset Retirement Obligations

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.

During the year ended December 31, 2010, we recognized $6.1 million of AROs for specific assets that we intend to retire for operational purposes. We recorded accretion expense of $0.28 million and $0.33 million in our consolidated statements of operations for the three months ended March 31, 2010 and 2011, respectively, related to these AROs.

No assets are legally restricted for purposes of settling our ARO during the three months ended March 31, 2010 and 2011. Following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for the three months ended March 31, 2010 and 2011, respectively.


	Three Months Ended
	March 31
	2010		2011
	(in thousands)

Balance at beginning of period	$	—	$	7,249
Additions		6,058		—
Expenditures		—		(7	)
Accretion expense		278		332

Balance at end of period	$	6,336	$	7,574

The Partnership did not recognize AROs as of December 31, 2009 given that, at that time, it did not intend to retire any of its existing assets, nor were retirement costs estimable. However, after the Partnership had obtained sufficient operating experience with assets during 2010, it determined certain assets would be retired from an operational perspective.


7.	Long-Term Debt

On November 4, 2009, we entered into an $85 million secured credit facility (“credit facility”) with a consortium of lending institutions. The credit facility is composed of a $50 million term loan facility and a $35 million revolving credit facility.

F-12

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

Our outstanding borrowings under the credit facility at December 31, 2010 and March 31, 2011, respectively, were:


	December 31,		March 31,
	2010		2011
	(in thousands)

Term loan facility	$	45,000	$	43,500
Revolving loan facility		11,370		13,000

		56,370		56,500
Less: Current portion		6,000		7,000

	$	50,370	$	49,500

At December 31, 2010 and March 31, 2011, letters of credit outstanding under the credit facility were $0.6 million.

The credit facility provides for a maximum borrowing equal to the lesser of (i) $85 million less the required amortization of term loan payments and (ii) 3.50 times adjusted consolidated EBITDA (as defined: $18.8 million at December 31, 2010 and $20.6 million at March 31, 2011). We may elect to have loans under the credit facility bear interest either (i) at a Eurodollar-based rate with a minimum of 2.0% plus a margin ranging from 3.25% to 4.0% depending on our total leverage ratio then in effect, or (ii) at a base rate (the greater of (i) the daily adjusting LIBOR rate and (ii) a Prime-based rate which is equal to the greater of (A) the Prime Rate and (B) an interest rate per annum equal to the Federal Funds Effective Rate in effect that day, plus one percent) plus a margin ranging from 2.25% to 3.00% depending on the total leverage ratio then in effect. We also pay a facility fee of 1.0% per annum. In December 2009, we entered into an interest rate cap with participating lenders with a $25.0 million notional amount at March 31, 2011 that effectively caps our Eurodollar-based rate exposure on that portion of our debt at a maximum of 4.0%. For the three months ended March 31, 2010 and 2011, the weighted average interest rate on borrowings under our credit facility was approximately 7.82% and 7.80%, respectively.

Our obligations under the credit facility are secured by a first mortgage in favor of the lenders in our real property. The terms of the credit facility include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, November 3, 2012.

The term loan facility also provides for quarterly principal installment payments as described below:


Year	Amount
	(in thousands)

2011	$	6,000
2012		39,000

	$	45,000

The credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the credit facility are (i) a total leverage ratio test (not to exceed 3.50 times) and a minimum interest coverage ratio test (not less than 2.50 times). We were in compliance with all of the covenants under our credit facility as of December 31, 2010 and March 31, 2011.

F-13

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

Fair Market Value of Financial Instruments

The Partnership used various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of the Partnership’s credit facility approximates fair value, because the interest rate on the facility is variable.


8.	Partners’ Capital

The number of units outstanding were as follows:


	December 31,		March 31,
	2010		2010
	(in thousands)

Common units		11,049		11,081
General partner units		224		224

Distributions

The Partnership made distributions of $0 million and $3.7 million for the three months ended March 31, 2010 and 2011, respectively. The Partnership made no distributions in respect of our general partner’s incentive distribution rights.


9.	Long-Term Incentive Plan

Our general partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our general partner adopted a long-term incentive plan for its employees and consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our general partner adopted an amended and restated long-term incentive plan (as amended, the “LTIP”). The LTIP currently permits the grant of awards in the form of Partnership units, which may include distribution equivalent rights (“DER”s), covering an aggregate of 625,532 of our units. A DER entitles the grantee to a cash payment equal to the cash distribution made by the Partnership with respect to a unit during the period such DER is outstanding. At December 31, 2010 and March 31, 2011, 111,112 and 71,112 units, respectively, were available for future grant under the LTIP.

Ownership in the awards is subject to forfeiture until the vesting date. The LTIP is administered by the board of directors of our general partner. The board of directors of our general partner, at its discretion, may elect to settle such vested phantom units with a number of units equivalent to the fair market value at the date of vesting in lieu of cash. Although, our general partner has the option to settle in cash upon the vesting of phantom unit our general partner does not intend to settle these awards in cash.

Although other types of awards are contemplated under the LTIP, currently outstanding awards are phantom units with DERs (392,315 at March 31, 2011) and phantom units without DERs (40,000 at March 31, 2011).

F-14

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

Grants issued under the LTIP have historically vested in increments of 25% on each of the first four anniversary dates of the date of the grant and do not contain any other restrictive conditions related to vesting other than continued employment.

During 2011, the fair value of the grants issued was calculated by the general partner based on several valuation models, including: a DCF model, a comparable company multiple analysis and a comparable recent transaction multiple analysis. As it relates to the DCF model, the model includes certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. Both the comparable company analysis and recent transaction analysis contain significant assumptions consistent with the DCF model, in addition to assumptions related to comparability, appropriateness of multiples (primarily based on EBITDA and DCF) and certain assumptions in the calculation of enterprise value.

The following table summarizes our unit-based awards for each of the periods indicated, in units:


	Three Months Ended March 31,
	2010		2011

Outstanding at beginning of period		361,052		424,157
Granted		127,368		40,000
Converted		—		(31,842	)

Outstanding at end of period		488,420		432,315

Grant date fair value per share	$	10.0	$	10.0 to $13.67

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at each balance sheet date. Compensation costs related to these awards for the three months ended March 31, 2010 and 2011 was $0.25 million and $0.35 million, respectively, which is classified in selling, general and administrative expenses in the consolidated statement of operations and partners’ capital on the consolidated balance sheet.

The total compensation cost related to nonvested awards not yet recognized on December 31, 2010 and March 31, 2011 was $3.9 million and $4.1 million, respectively, and the weighted average period over which this cost is expected to be recognized is approximately 3 years.


10.	Commitments and Contingencies

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipeline operations and we could, at times, be subject to environmental cleanup and enforcement actions. We attempt to manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.

Future noncancelable commitments related to certain contractual obligations are presented below:


	Payments Due by Period (in thousands)
	Total		2011		2012		2013		2014		2015		Thereafter

Operating leases and service contract	$	2,057	$	580	$	405	$	342	$	351	$	349	$	30
ARO		8,340		914		—		—		—		—		7,426

Total	$	10,397	$	1,494	$	405	$	342	$	351	$	349	$	7,456

F-15

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:


	Three Months Ended March 31,
	2010		2011
	(in thousands)

Operating leases	$	106	$	250
ARO		—		7

	$	106	$	257


11.	Related-Party Transactions

Employees of our general partner are assigned to work for us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by our general partner to American Midstream, LLC which, in turn, charges the appropriate subsidiary. Our general partner does not record any profit or margin for the administrative and operational services charged to us. During the three months ended March 31, 2010 and 2011, administrative and operational services expenses of $0.03 million and $0.02 million, respectively, were allocated to us by our general partner.

We have entered into an advisory services agreement with American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C., and American Infrastructure MLP Associates Management, L.L.C., as the advisors. The agreement provides for the payment of $0.3 million in 2010 and annual fees of $0.3 million plus annual increases in proportion to the increase in budgeted gross revenues thereafter. In exchange, the advisors have agreed to provide us services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services. For the three months ended March 31, 2010 and 2011, less than $0.1 million and $0.1 million, respectively, had been recorded to selling, general and administrative expenses under this agreement.


12.	Reporting Segments

Our operations are located in the United States and are organized into two reporting segments: (1) Gathering and Processing; and (2) Transmission.

Gathering and Processing

Our Gathering and Processing segment provides “wellhead to market” services to producers of natural gas and oil, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas and NGLs to various markets and pipeline systems.

Transmission

Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.

These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment.

F-16

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

The following tables set forth our segment information:


			Gathering
			and
	Transmission		Processing		Total
			(in thousands)

Three months ended March 31, 2010
Total revenue	$	8,088	$	46,624	$	54,712
Segment gross margin(a)	$	3,650	$	6,098	$	9,748
Direct operating expenses						2,692
Selling, general and administrative expenses						2,113
One-time transaction costs						74
Depreciation expense						4,966
Interest expense						1,357

Net income (loss)					$	(1,454	)


			Gathering
			and
	Transmission		Processing			Total
			(in thousands)

Three months ended March 31, 2011
Total revenue	$	19,181	$	48,084		$	63,765
Segment gross margin(a)(b)	$	4,145	$	8,167		$	12,312
Unrealized losses included in revenue		—		(3,500	)		(3,500	)
Direct operating expenses							3,058
Selling, general and administrative expenses							2,675
One-time transaction costs							288
Depreciation expense							5,037
Interest expense							1,264

Net income (loss)						$	(3,510	)


(a)		Segment gross margin for our Gathering and Processing segment consists of total revenue less purchases of natural gas, NGLs and condensate. Segment gross margin for our Transmission segment consists of total revenue, less purchases of natural gas. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(b)		Unrealized gains (losses) from derivative mark-to-market adjustments is included in total revenue and segment gross margin in our Gathering and Processing segment for the three months ended March 31, 2010. Effective January 1, 2011, we changed our gross margin and segment gross margin measure to exclude unrealized non cash mark-to-market adjustments related to our commodity derivatives. There were no such adjustments for the three months ended March 31, 2010 and $3.5 in unrealized losses were excluded from segment gross margin for the three months ended March 31, 2011.

Asset information including capital expenditures, by segment is not included in reports used by our management in its monitoring of performance and therefore, is not disclosed.

F-17

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

For the purposes of our Transmission segment, for the three months ended March 31, 2010 and 2011, Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented significant customers, each representing more than 10% of our segment revenue in this segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented $5.4 million, $0.1 million and $0.8 million of segment revenue for the three months ended March 31, 2010 and $4.4 million, $9.6 million and $0.8 million for the three months ended March 31, 2011, respectively.

For the purposes of our Gathering and Processing segment, for the three months ended March 31, 2010 and 2011, Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented significant customers, each representing more than 10% of our segment revenue in this segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented $24.1 million, $7.1 million and $5.7 million of segment revenue for the three months ended March 31, 2010 and $7.6 million, $28.5 million and $3.9 million for the three months ended March 31, 2011, respectively.


13.	Net Income (Loss) per Limited and General Partner Unit

Net Income per Limited Partner Unit. Net income is allocated to the general partner and the limited partners (common unitholders) in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of outstanding limited partner units during the period.

Unvested share-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit.

We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. We have no dilutive securities, therefore basic and diluted net income per unit are the same.

F-18

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

We determined basic and diluted net income per general partner unit and limited partner unit as follows:


	For the Three Months Ended March 31,
	2010			2011
	(in thousands, except per unit amounts)

Net loss attributable to general partner and limited partners	$	(1,454	)	$	(3,510	)
Weighted average general partner and limited partner units outstanding(a)		10,402			11,697
Earnings per general partner and limited partner unit (basic and diluted)	$	(0.14	)	$	(0.30	)
Net loss attributable to limited partners	$	(1,425	)	$	(3,440	)
Weighted average limited partner units outstanding(a)		10,202			11,473
Earnings per limited partner unit (basic and diluted)	$	(0.14	)	$	(0.30	)
Net loss attributable to general partner	$	(29	)	$	(70	)
Weighted average general partner units outstanding		200			224
Earnings per general partner unit (basic and diluted)	$	(0.15	)	$	(0.31	)


(a)		Includes unvested phantom units, which are considered participating securities, of 424,157 and 392,315 as of December 31, 2010 and March 31, 2011, respectively.


14.	Subsequent Events

The Partnership has evaluated subsequent events through June 9, 2011:

On March 31, 2011, we filed a registration statement with the Securities and Exchange Commission relating to a proposed public offering of shares of our common units (the “IPO”), and have from time to time thereafter amended such registration statement. The registration statement, as amended, reflects our intentions to use a portion of the net proceeds of the offering and borrowings under our new credit facility to make a special distribution to pre-offering unitholders of record and our general partner. At an assumed offering price of $20.00 per common unit, the aggregate distribution to those unitholders and our general partner would be approximately $30.0 million.

On May 4, 2011, the Board of Directors of our general partner approved a distribution in the amount of $3.7 million, consisting of $3.6 million to the limited partners and $0.1 million to the general partner, as well as a payment of $0.1 million in respect of DERs outstanding and $0.1 million in DER payments.

On June 2, 2011, our Board of Directors determined that we would gain operational and strategic flexibility from cancelling our then-existing swap contracts that we entered into in January 2011. In conjunction with un-winding and cancelling these contracts, we entered into new swap contracts that extend through the end of 2012. We did not modify the put contracts we entered into through our January 2011 hedge transactions.

In July 2011, in the course of preparing our annual filing for 2010 with the Mississippi Department of Environmental Quality (“MDEQ”) as required by our Title V Air Permit, we determined that we underreported to MDEQ the SO₂ emissions from the Bazor Ridge plant for 2009 and 2010. Moreover, we recently discovered that SO₂ emission levels during 2009 may have exceeded the threshold that triggers the need for a Prevention of Significant Deterioration, or a PSD, permit under the federal Clean Air Act. No PSD permit has been issued for the Bazor Ridge plant. In addition, we recently determined that certain SO₂ emissions during 2009 and 2010 exceeded the reportable quantity threshold under the federal Emergency Planning and Community Right-to-Know Act, or EPCRA, requiring notification of various

F-19

American Midstream Partners, LP and Subsidiaries

Notes to Unaudited Consolidated Financial Statements

December 31, 2010 and March 31, 2011 and the Three Months Ended March 31, 2010 and 2011 – (continued)

governmental authorities. We did not make any such EPCRA notifications. In July 2011, we self-reported these issues to the MDEQ and the EPA.

If the MDEQ or the EPA were to initiate enforcement proceedings with respect to 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. If the Bazor Ridge plant were subject to any curtailment or other operational restrictions as a result of any such enforcement proceeding, or were required to incur additional capital expenditures for additional emission controls through any permitting process, the costs to us could be material. Although enforcement proceedings are reasonably possible, we cannot estimate the financial impact on us from such enforcement proceedings until we have completed an investigation of these matters and met with the agencies to determine treatment, extent, and reportability any of exceedances and violations. As a result, we have not recorded a loss contingency as the criteria under ASC 450, Contingencies, has not been met.

In addition, 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, though not probable at this time, that one or both of the 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 them for any losses (as defined in the purchase agreement) that may result. Because the existence and extent of any violations is unknown at this time, the financial impact of any amounts due regulatory agencies and/or the prior owner cannot be reasonably estimated at this time.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of the General Partner of

American Midstream Partners, LP

We have audited the accompanying consolidated balance sheets of American Midstream Partners, LP and its subsidiaries as of December 31, 2009 and 2010, and the related consolidated statements of operations, of changes in partners’ capital and of cash flows for the period from August 20, 2009 (inception date) to December 31, 2009 and year ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Midstream Partners, LP and its subsidiaries at December 31, 2009 and 2010, and the results of their operations and their cash flows for the period from August 20, 2009 (inception date) to December 31, 2009 and year ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 30, 2011

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American Midstream Partners, LP and Subsidiaries

Consolidated Balance Sheets

December 31, 2009 and 2010


	December 31,
	2009		2010
	(in thousands)

Assets
Current assets
Cash and cash equivalents	$	1,149	$	63
Accounts receivable, net		1,447		656
Unbilled revenue		18,329		22,194
Other current assets		1,523		1,523

Total current assets		22,448		24,436

Property, plant and equipment, net		149,266		146,808
Other assets		2,679		1,985
Risk management assets		77		—

Total assets	$	174,470	$	173,229

Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	1,934	$	980
Accrued gas purchases		14,881		18,706
Current portion of long-term debt		5,000		6,000
Other loans		815		615
Accrued expenses and other current liabilities		2,237		2,676

Total current liabilities		24,867		28,977
Other liabilities		399		8,078
Long-term debt		56,000		50,370

Total liabilities		81,266		87,425

Commitments and contingencies (see Note 16)
Partners’ capital
General partner interest (0.2 million units outstanding as of December 31, 2010 and 2009)		2,010		2,124
Limited partner interest (9.8 million and 11.0 million units outstanding as of December 31, 2010 and 2009, respectively)		91,148		83,624
Accumulated other comprehensive income		46		56

Total partners’ capital		93,204		85,804

Total liabilities and partners’ equity	$	174,470	$	173,229

The accompanying notes are an integral part of these consolidated financial statements.

F-22

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Operations

Period from August 20, 2009 (Inception Date) to

December 31, 2009 and Year Ended December 31, 2010


	Period from
	August 20,
	2009
	(Inception Date)
	to			Year Ended
	December 31,			December 31,
	2009			2010
	(in thousands)

Total revenue	$	32,833		$	211,940
Operating expenses:
Purchases of natural gas, NGLs and condensate		26,593			173,821
Direct operating expenses		1,594			12,187
Selling, general and administrative expenses		1,346			8,854
One-time transaction costs		6,404			303
Depreciation expense		2,978			20,013

Total operating expenses		38,915			215,178

Operating income (loss)		(6,082	)		(3,238	)
Other expenses (income):
Interest expense		910			5,406

Net income (loss)	$	(6,992	)	$	(8,644	)

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

Limited partners’ interest in net income (loss)	$	(6,852	)	$	(8,471	)

Limited partners’ net income (loss) per common unit (Note 19)	$	(1.52	)	$	(.81	)

Weighted average number of common units used in computation of limited partners’ net income (loss) per common unit		4,507			10,506

Pro forma earnings per common and subordinated units (see Note 1)				$	(1.63	)
Pro forma weighted average common and subordinated units outstanding (see Note 1)					5,199

The accompanying notes are an integral part of these consolidated financial statements.

F-23

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Changes in Partners’ Capital
Period from August 20, 2009 (Inception Date) to

December 31, 2009 and Year Ended December 31, 2010


												Accumulated
	Limited			Limited			General		General			Other
	Partner			Partner			Partner		Partner			Comprehensive
	Units			Interest			Units		Interest			Income		Total
	(in thousands)

Balances at August 20, 2009 (Inception Date)		9,800		$	—			200	$	—		$	—	$	—

Contributions by partners		—			98,000			—		2,000			—		100,000
Net loss		—			(6,852	)		—		(140	)		—		(6,992	)
Unit based compensation		—			—			—		150			—		150
Adjustments to other post retirement benefit plan assets and liabilities		—			—			—		—			46		46


Balances at December 31, 2009		9,800		$	91,148			200	$	2,010		$	46	$	93,204

Contributions by partners		1,176			11,760			24		240			—		12,000
Net loss		—			(8,471	)		—		(173	)		—		(8,644	)
Unitholder distributions		—			(11,545	)		—		(234	)		—		(11,779	)
LTIP vesting		90			903			—		(903	)		—		—
Tax netting repurchase		(17	)		(171	)		—		—			—		(171	)
Unit based compensation		—			—			—		1,184			—		1,184
Adjustments to other post retirement benefit plan assets and liabilities		—			—			—		—			10		10

Balances at December 31, 2010		11,049		$	83,624			224	$	2,124		$	56	$	85,804

The accompanying notes are an integral part of these consolidated financial statements.

F-24

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Cash Flows

Period from August 20, 2009 (Inception Date) to

December 31, 2009 and Year Ended December 31, 2010


	Period from
	August 20,
	2009
	(Inception Date)
	to			Year Ended
	December 31,			December 31,
	2009			2010
	(in thousands)

Cash flows from operating activities
Net loss	$	(6,992	)	$	(8,644	)
Adjustments to reconcile change in net assets to net cash used in operating activities:
Depreciation expense		2,978			20,013
Amortization of deferred financing costs		118			807
Mark to market on derivatives		5			385
Unit based compensation		150			1,185
Changes in operating assets and liabilities:
Accounts receivable		(1,447	)		791
Unbilled revenue		(18,329	)		(3,865	)
Risk management assets		(82	)		(308	)
Other current assets		(1,523	)		—
Other assets		(199	)		(104	)
Accounts payable		1,934			(954	)
Accrued gas purchase		14,881			3,825
Accrued expenses and other current liabilities		1,997			268
Other liabilities		(22	)		392

Net cash provided (used) in operating activities		(6,531	)		13,791

Cash flows from investing activities
Acquisition of operating assets from Enbridge Midcoast Energy, LP		(150,818	)		—
Additions to property, plant and equipment		(1,158	)		(10,268	)

Net cash used in investing activities		(151,976	)		(10,268	)

Cash flows from financing activities
Capital contributions		100,000			12,000
Unit holder distributions		—			(11,779	)
Payment of deferred financing costs		(2,158	)		—
Borrowings on other loans		903			800
Payments on other loan		(89	)		(1,000	)
Borrowings on long-term debt		63,000			26,500
Payments on long-term debt		(2,000	)		(31,130	)

Net cash provided (used) by financing activities		159,656			(4,609	)

Net increase (decrease) in cash and cash equivalents		1,149			(1,086	)
Cash and cash equivalents
Beginning of period		—			1,149

End of period	$	1,149		$	63

Supplemental cash flow information
Interest payments	$	337		$	4,523

The accompanying notes are an integral part of these consolidated financial statements.

F-25

American Midstream Partners, LP and Subsidiaries

Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010


1.	Summary of Significant Accounting Policies

Nature of Business

We are controlled by our general partner, American Midstream GP, LLC, which is a wholly owned subsidiary of AIM Midstream Holdings, LLC.


	•	American Midstream (Midla), LLC, which owns and operates approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana.

	•	American Midstream (AlaTenn), LLC, which owns and operates more than approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an eight county area in Alabama, Mississippi and Tennessee.

Basis of Presentation

We have prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of American Midstream Partners, LP and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.

The financial position at December 31, 2009 and results of operations and changes in cash flows for the period then ended reflect operations from August 20, 2009, the date of inception. Between the date of inception and the date of the acquisition of the assets discussed in Note 2 on November 2, 2009, no operating activity occurred in the Partnership.

Use of Estimates

When preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and

F-26

(5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.

Accounting for Regulated Operations

Certain of our natural gas pipelines are subject to regulation by the FERC. The FERC exercises statutory authority over matters such as construction, transportation rates we charge and our underlying accounting practices, and ratemaking agreements with customers. Accordingly, we record costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a non-regulated entity. Also, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for our regulated entities. As of December 31, 2009 and 2010, the Partnership had no such significant regulatory assets or liabilities.

Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas

We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectibility is reasonably assured. We record revenue and cost of product sold on a gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that are purchased for resale. We do not have multiple elements in our revenue contracts with our customers. When our customers pay us a fee for providing a service such as gathering, treating or transportation, we record those fees separately in revenues. For the period and year ended December 31, 2009 and 2010, respectively, the Partnership had the following revenues by category:


	Period from
	August 20
	2009
	(Inception Date)
	to		Year Ended
	December 31,		December 31,
	2009		2010
	(in thousands)

Revenue
Transportation — firm	$	2,274	$	10,610
Transportation — interruptible		444		3,313
Sales of natural gas, NGLs and condensate		30,078		197,398
Other		37		619

Total revenue	$	32,833	$	211,940

We derive revenue in our business from the following types of arrangements:

Fee-Based

Under these arrangements, we generally are paid a fixed cash fee for gathering and transporting natural gas. Fee-based revenues, which are included in sales of natural gas, NGLs and condensate above, are recorded when services have been provided, and collectability of the revenue is reasonably assured.

Percent-of-Proceeds, or POP

Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas and NGLs

F-27

at market prices. Where we provide processing services at the processing plants that we own, or obtain processing services for our own account under our elective processing arrangements we typically retain and sell a percentage of the residue natural gas and resulting NGLs. We recognize percent-of-proceeds contract revenue, which is included in sales of natural gas, NGLs and condensate above, when the natural gas, NGL’s or condensate is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

Fixed-Margin

Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We recognize revenue from fixed-margin contracts, which is included in sales of natural gas, NGLs and condensate above, when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

Firm Transportation

Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us. Firm transportation revenue is recorded when products are delivered, services have been provided and collectability of the revenue is reasonably assured.

Interruptible Transportation

Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped. Interruptible transportation revenue is recorded when products are delivered, services have been provided, and collectability of the revenue is reasonably assured.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. For each of the period and year ended December 31, 2009 and 2010, the Partnership recorded no allowances for losses on accounts receivable.

Our predecessor financial statements included certain allowance for doubtful accounts in relation with the recoverability of certain customers accounts. In connection with our acquisition of the Enbridge assets, we did not acquire any working capital accounts (which includes accounts receivable) as of November 1, 2009.

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Inventory

Inventory includes primarily product inventory. The Partnership records all product inventories at the lower of cost or market (“LCM”), which is determined on a weighted average basis.

Operational Balancing Agreements and Natural Gas Imbalances

To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gas imbalances are recorded as gas imbalances and classified within other current assets or other current liabilities on our consolidated balance sheets based on the market value. Natural gas imbalances are recorded as gas imbalances within “Accrued gas purchases” on the consolidated balance sheets.

Property, Plant and Equipment

We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year for (1) assets purchased or constructed; (2) existing assets that are replaced, improved, or the useful lives of which have been extended; and (3) all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over its estimated useful life. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar entities.

The Partnership calculated the fair value of the assets acquired from Enbridge Pipelines, LP in November 2009 with the assistance of an independent third party valuation firm. This valuation was performed primarily using a discounted cash flow model that included certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. Management created the projections, reviewed the calculations, assumptions and valuation methodology used to determine the fair value of the assets acquired. Management determined the final fair values to assign to the assets and liabilities in determining the purchase price allocation and had sole responsibility for those items in the financial statements.

Impairment of Long Lived Assets

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses, the market and business environment to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market

F-29

prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income. No impairment losses were recognized during the period ended and year ended December 31, 2009 and 2010.

We assess our long-lived assets for impairment using authoritative guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Fair values, for the purposes of the impairment test, are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

Examples of long-lived asset impairment indicators include:


	•	A significant decrease in the market price of a long-lived asset or group;

	•	A significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;

	•	A significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;

	•	An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group; and

	•	A current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long lived asset or asset group;

	•	A current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

Income Taxes

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships. The Texas margin tax is computed on our modified gross margin and was not significant for each of the period or year ended December 31, 2009 and 2010.

Net income for financial statement purposes may differ significantly from taxable income allocable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available.

Commitments, Contingencies and Environmental Liabilities

We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate

F-30

that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also take into account our prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements.

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for a minority of our onshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management’s experience, or the asset’s estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.

Asset Retirement Obligations (“AROs”)

AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. We depreciate the capitalized ARO using the straight-line method over the period during which the related long-lived asset is expected to provide benefits. After the initial period of ARO recognition, we revise the ARO to reflect the passage of time or revisions to the amounts of estimated cash flows or their timing.

Derivative Financial Instruments

Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt, commodity prices and fractionation margins (the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases). In an effort to manage the risks to unitholders, we use a variety of derivative financial instruments including swaps, put options and interest rate caps to create offsetting positions to specific commodity or interest rate exposures. In accordance with the authoritative accounting guidance, we record all derivative financial instruments in our consolidated balance

F-31

sheets at fair market value. We record the fair market value of our derivative financial instruments in the consolidated balance sheets as current and long-term assets or liabilities on a net basis by counterparty. We record changes in the fair value of our derivative financial instruments in our consolidated statements of operations as follows:


	•	Commodity-based derivatives: “Total revenue”

	•	Corporate interest rate derivatives: “Interest expense”

Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of our general partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction, and we do not use derivative financial instruments for speculative purposes.

The price assumptions we use to value our derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from over-the-counter, or OTC, market makers to find executable bids and offers. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

Our earnings are affected by use of the mark-to-market method of accounting as required under GAAP for derivative financial instruments. The use of mark-to-market accounting for derivative financial instruments can cause noncash earnings volatility resulting from changes in the underlying indices, primarily commodity prices.

The Partnership’s other comprehensive income is comprised of changes in the net pension asset or liability associated with the OPEB plan (Note 15). Comprehensive income for the period and year ended December 31, 2009 and 2010 was as follows:


	Period Ended			Year Ended
	December 31, 2009			December 31, 2010

Net income (loss)	$	(6,992	)	$	(8,644	)
Unrealized gains (losses) on post retirement benefit plan assets and liabilities		46			10

Comprehensive income (loss)	$	(6,946	)	$	(8,634	)

Unit-Based Employee Compensation

We award unit-based compensation to management, nonmanagement employees and directors in the form of phantom units, which are deemed to be equity awards. Compensation expense on phantom units is measured by the fair value of the award at the date of grant as determined by management. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 14.

Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of our derivative instruments and disclosures associated with our outstanding indebtedness. We define fair value as an exit price

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representing the expected amount we would receive when selling an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:


	•	Level 1 — We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. We have no assets and liabilities included in this category.

	•	Level 2 — We categorize the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument, as Level 2. Assets and liabilities that we value using either models or other valuation methodologies are derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (a) quoted prices for assets and liabilities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. We have no fair value of assets or liabilities included in this category.

	•	Level 3 — We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include debt and derivative instruments for which we do not have sufficient corroborating market evidence support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: nonbinding broker quotes, time value, volatility, correlation and extrapolation methods.

We utilize a mid-market pricing convention, or the “market approach,” for valuation for assigning fair value to our derivative assets and liabilities. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchase and debt extinguishments include any associated unamortized debt issue costs.

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Limited Partners’ Net Income Per Unit

We compute Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period. The overall computation, presentation, and disclosure requirements for our Limited Partners’ Net Income per Unit are made in accordance with the “Earnings per Share” Topic of the Codification.

Pro Forma Earnings Per Common and Subordinated Unit

The pro forma earnings per common and subordinated unit provides supplemental information in connection with our proposed initial public offering. The pro forma earnings per common and subordinated unit is calculated by dividing earnings attributable to common and subordinated units by the pro forma units, giving effect to the Recapitalization Transactions as of December 31, 2010 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 dividend that will be funded from the proceeds of this offering that exceeds net income for the year ended December 31, 2010.

The following table sets forth a reconciliation between historical weighted average common units used in the computation of limited partners’ equity income (loss) per common unit at December 31, 2010 to the pro forma weighted average common and subordinated units outstanding used in the calculation of pro forma earnings per common and subordinated unit (in thousands of units):


Historical weighted average common units used in the computation of limited partners’ net income (loss) per common unit	10,506
Impact of reverse unit split into 0.485 common units	(5,407	)
Additional number of common units issued in this offering (at an assumed offering price of $20.00) necessary to pay a portion of the distribution to LTIP participants holding common units, AIM Midstream Holdings and our general partner that will be funded from the proceeds of this offering that exceeds net income	100

Pro forma weighted average common and subordinated units outstanding used in the calculation of pro forma earnings per common and subordinated unit	5,199

Accounting Pronouncements Recently Adopted

In December 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2009-16, “Accounting for Transfers of Financial Assets” and Accounting Standards Update No. 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities.” ASU No. 2009-16 amended the Codification’s “Transfers and Servicing” Topic to include the provisions included within the FASB’s previous Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets — an amendment of FASB Statement No. 140,” issued June 12, 2009. ASU No. 2009-17 amended the Codification’s “Consolidations” Topic to include the provisions included within the FASB’s previous SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” also issued June 12, 2009. These two Updates changed the way entities must account for securitizations and special-purpose entities. ASU No. 2009-16 requires more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transfer financial assets. ASU No. 2009-17 changes how a company determines whether an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. For us, both Updates were effective January 1, 2010; however, the adoption of these Updates did not have any impact on our consolidated financial statements.

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In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Improving Disclosures about Fair Value Measurements.” This ASU requires both the gross presentation of activity within the Level 3 fair value measurement roll forward and the details of transfers in and out of Levels 1 and 2 fair value measurements. It also clarifies certain disclosure requirements on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques. For us, this ASU was effective January 1, 2010 (except for the Level 3 roll forward which was effective for us January 1, 2011); however, the adoption of this ASU did not have a material impact on our consolidated financial statements. Furthermore, during each of the period and year ended December 31, 2010 and 2009, we made no transfers in and out of Level 1, Level 2, or Level 3 of the fair value hierarchy.

In July 2010, the FASB issued Accounting Standards Update No. 2010-20, “Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses.” ASU No. 2010-20 requires companies that hold financing receivables, which include loans, lease receivables, and the other long-term receivables to provide more information in their disclosures about the credit quality of their financing receivables and the credit reserves held against them. On December 31, 2010, we adopted all amendments that require disclosures as of the end of a reporting period, and on January 1, 2011, we adopted all amendments that require disclosures about activity that occurs during a reporting period (the remainder of this ASU). The adoption of this ASU did not have a material impact on our consolidated financial statements.


2.	Acquisition

The acquired businesses were renamed as follows:

American Midstream (Alabama Intrastate), LLC

American Midstream (Bamagas Intrastate), LLC

American Midstream (Tennessee River), LLC

American Midstream (Mississippi), LLC

American Midstream (Midla), LLC

American Midstream (Alabama Gathering), LLC

American Midstream (AlaTenn), LLC

American Midstream Onshore Pipelines, LLC

Mid Louisiana Gas Transmission, LLC

American Midstream Offshore (Seacrest), LP

American Midstream (SIGCO Intrastate), LLC

American Midstream (Louisiana Intrastate), LLC

The acquisition qualifies as a business combination and, as such, the Partnership estimated the fair value of each property as of the acquisition date (the date on which the Partnership obtained control of the properties). The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. The Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, expectations for timing and amount of future development and operating costs, projections of future rates of production, and risk adjusted discount rates. These assumptions represent Level 3 inputs.

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The following table summarizes the consideration paid to the seller and the amounts of the assets acquired and liabilities assumed in the acquisition.


	(in thousands)

Consideration paid to seller
Cash consideration	$	150,818

Recognized amounts of identifiable assets acquired and liabilities assumed
Property, plant and equipment		151,085
Other post-retirement benefit plan assets, net		394
Other liabilities assumed		(661	)

Total identifiable net assets	$	150,818

Acquisition costs of $6.4 million and $0.3 million have been recorded in the statements of operations under the caption Transaction costs on acquisitions for the period and year ended December 31, 2009 and 2010.


3.	Concentration of Credit Risk and Trade Accounts Receivable

Enbridge Marketing (US) L.P., ConocoPhillips Corporation and ExxonMobil Corporation were significant customers, representing at least 10% of our consolidated revenue, accounting for $17.8 million, $5.0 million and $0.1 million, respectively, of our consolidated revenue in the consolidated statement of operations in the period ended December 31, 2009 and $63.9 million, $53.4 million and $22.9 million for the year ended December 31, 2010.


4.	Other Current Assets

Other current assets as of December 31 were as follows:


	2009		2010
	(in thousands)

Prepaid insurance — current portion	$	815	$	767
NGL inventory		121		101
Other receivables		431		30
Other prepaid amounts		156		625

	$	1,523	$	1,523

For each of the period and year ended December 31, 2009 and 2010, the Partnership recorded no LCM write-downs.

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5.	Derivatives

Commodity Derivatives

Neither the Partnership nor its counterparties are required to post collateral in connection with its derivative positions and netting agreements are in place with each of the Partnership’s counterparties allowing the Partnership to offset its commodity derivative asset and liability positions.

As of December 31, 2010, the notional volumes of our commodity hedges for 2011 were 2,404,584 gallons, with no amounts hedged in 2012 or after.

Interest Rate Derivatives

The Partnership also utilizes interest rate caps to protect against changes in interest rates on its floating rate debt.

At December 31, 2010, the Partnership had $56.4 million outstanding under its credit facility, with interest accruing at a rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates, the Partnership has entered into interest rate caps that mitigate the risk of increases in interest rates. As of December 31, 2010, we had interest rate caps with a notional amount of $26.5 million that effectively fix the base rate on that portion of our debt, with a fixed maximum rate of 4%.

As of December 31, 2009 and 2010, the fair value associated with the Partnership’s derivative instruments were recorded in our financial statements, under the caption Risk management assets, as follows:


	December 31,		December 31,
	2009		2010
	(in thousands)

Commodity derivatives	$	—	$	—
Interest rate derivatives		77		—

	$	77	$	—

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During 2009 and 2010, we recorded the following mark-to-market losses:


	December 31,			December 31,
	2009			2010
	(in thousands)

Commodity derivatives	$	—		$	(308	)
Interest rate derivatives		(5	)		(77	)

	$	(5	)	$	(385	)

Fair Value Measurements

The Partnership’s interest rate caps and commodity derivatives discussed above were classified as Level 3 derivatives for all periods presented.


	Period from
	August 20, 2009
	(Inception Date)
	to			Year Ended
	December 31,			December 31,
	2009			2010
	(in thousands)

Fair value asset (liability), beginning of period	$	—		$	77
Total realized and unrealized (losses) gains included in revenue		(5	)		(385	)
Purchases, sales and settlements, net		82			308

Fair value (liability) asset, end of period	$	77		$	—

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6.	Property, Plant and Equipment, Net

Property, plant and equipment, net, as of December 31 were as follows:


	Useful Life		2009			2010
			(in thousands)

Land			$	41		$	41
Buildings and improvements		4 to 40		1,427			2,523
Processing and treating plants		8 to 40		10,255			11,954
Pipelines		5 to 40		131,845			143,805
Compressors		4 to 20		7,164			7,163
Equipment		8 to 20		825			1,711
Computer software		5		687			1,390

Total property, plant and equipment				152,244			168,587
Accumulated depreciation				(2,978	)		(21,779	)

Property, plant and equipment, net			$	149,266		$	146,808

Of the gross property, plant and equipment balances at December 31, 2009 and 2010, $20.3 million and $24.3 million, respectively, relate to regulated assets.


7.	Asset Retirement Obligations

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.

During the year ended December 31, 2010, we recognized $6.1 million of AROs for specific assets that we intend to retire for operational purposes. We recorded accretion expense of $1.2 million, in our consolidated statements of operations for the year ended December 31, 2010 related to these AROs.

No assets are legally restricted for purposes of settling our ARO for each of the period and year ended December 31, 2009 and 2010. Following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for each of the period and year ended December 31, 2009 and 2010, respectively.

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	2009		2010
	(in thousands)

Balance at beginning of period	$	—	$	—
Additions	$	—		6,058
Accretion expense	$	—		1,191

Balance at end of period	$	—	$	7,249


8.	Other Assets, Net

Other assets, net, as of December 31 were as follows:


	2009		2010
	(in thousands)

Deferred financing costs	$	2,040	$	1,338
Other post-retirement benefit plan assets, net		440		450
Prepaid insurance — long term portion		189		140
Security deposits		10		57

	$	2,679	$	1,985

Deferred Financing Costs

Deferred financing costs related to the term loan portion of our credit facility are amortized using the effective interest method over the term of the term credit facility. See Note 12 for more information about our credit facility. Deferred financing costs related to the revolver portion of our credit facility are amortized on a straight line basis over the term of the credit facility. During the year ended December 31, 2010, we incurred deferred financing costs of $2.2 million related to our November 2009 $85 million credit facility.

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9.	Accrued Expenses and Other Current Liabilities

Other current liabilities as of December 31 were as follows:


	2009		2010
	(in thousands)

Accrued interest payable	$	508	$	407
Accrued expenses		651		839
Accrued salaries		267		957
Accrued property taxes		217		3
Contract obligations — short term		240		240
Deferred revenue		—		210
Other		354		20

	$	2,237	$	2,676


10.	Other Liabilities

Other long term liabilities as of December 31 were as follows:


	2009		2010
	(in thousands)

Deferred revenue	$	—	$	528
ARO		—		7,249
Contract obligations — long term		399		208
Other deferred expenses		—		93

	$	399	$	8,078


11.	Other Loan

Other loan represents insurance premium financing in the original amounts of $0.8 million bearing interest at 4.25% per annum, that is repayable in equal monthly installments of less than $0.1 million through October 1, 2011.


12.	Long-Term Debt

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Our outstanding borrowings under the credit facility at December 31 were:


	2009		2010
	(in thousands)

Term loan facility	$	50,000	$	45,000
Revolving loan facility		11,000		11,370

		61,000		56,370
Less: Current portion		5,000		6,000

	$	56,000	$	50,370

At December 31, 2009 and 2010, letters of credit outstanding under the credit facility were $2.0 million and $0.6 million, respectively.

The credit facility provides for a maximum borrowing equal to the lesser of (i) $85 million less the required amortization of term loan payments and (ii) 3.50 times adjusted consolidated EBITDA (as defined: $20.9 and $18.8 million at December 31, 2009 and 2010, respectively). We may elect to have loans under the credit facility bear interest either (i) at a Eurodollar-based rate with a minimum of 2.0% plus a margin ranging from 3.25% to 4.0% depending on our total leverage ratio then in effect, or (ii) at a base rate (the greater of (i) the daily adjusting LIBOR rate and (ii) a Prime-based rate which is equal to the greater of (A) the Prime Rate and (B) an interest rate per annum equal to the Federal Funds Effective Rate in effect that day, plus one percent) plus a margin ranging from 2.25% to 3.00% depending on the total leverage ratio then in effect. We also pay a facility fee of 1.0% per annum. In December 2009, we entered into an interest rate cap with participating lenders with a $26.5 million notional amount at December 31, 2010 that effectively caps our Eurodollar-based rate exposure on that portion of our debt at a maximum of 4.0%. For the period and year ended December 31, 2009 and 2010, the weighted average interest rate on borrowings under our credit facility was approximately 5.79% and 7.48%, respectively.

Our obligations under the credit facility are secured by first mortgage in favor of the lenders in our real property. The terms of the credit facility include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, November 3, 2012.

The term loan facility also provides for quarterly principal installment payments as described below:


Year	Amount
	(in thousands)

2011	$	6,000
2012		39,000

	$	45,000

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Fair Market Value of Financial Instruments


13.	Partners’ Capital

Our capital accounts are comprised of a 2% general partner interest and 98% limited partner interests. Our limited partners have limited rights of ownership as provided for under our partnership agreement and, as discussed below, the right to participate in our distributions. Our general partner manages our operations, and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that are nonvoting limited partner interests held by our general partner. Incentive distribution rights confer upon the holder thereof only the rights and obligations specifically provided in our partnership agreement. Under that agreement, our 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. Incentive distribution rights are not unitized and have no associated capital account. Our general partner may transfer these incentive distribution rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The number of units outstanding as of December 31, were as follows:


	2009		2010
	(in thousands)

Common units		9,800		11,049
General partner units		200		224

Distributions

The Partnership made distributions of $0 million and $11.8 million for the period and year ended December 31, 2009 and 2010, respectively. We issued our incentive distribution rights to our general partner in November 2009. However, as no such distributions are owed under our partnership agreement prior to the consummation our initial public offering, no distributions have been made to date on our incentive distribution rights. We have neither adopted a policy of nor were required to make minimum distributions during the periods presented in these financial statements.


14.	Long-Term Incentive Plan

Our general partner manages our operations and activities and employs the personnel who provide support to our operations. On November 2, 2009, the board of directors of our general partner adopted a long-term incentive plan for its employees and consultants and directors who perform services for it or its affiliates. On May 25, 2010, the board of directors of our general partner adopted an amended and restated long-term incentive plan (as amended, the “LTIP”). The LTIP currently permits the grant of awards in the form of Partnership units, which may include distribution equivalent rights (“DER”s), covering an aggregate of 625,532 of our units. A DER entitles the grantee to a cash payment equal to the cash distribution made by the Partnership with respect to a unit during the period such DER is outstanding. At December 31, 2009 and 2010, 154,737 and 111,112 units, respectively, were available for future grant under the LTIP.

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Ownership in the awards is subject to forfeiture until the vesting date. The LTIP is administered by the board of directors of our general partner.

Although other types of awards are contemplated under the LTIP, currently outstanding awards are limited to phantom units with DERs issued on November 2, 2009. The board of directors of our general partner, at its discretion, may elect to settle such vested phantom units with a number of units equivalent to the fair market value at the date of vesting in lieu of cash. Although, our general partner has the option to settle in cash upon the vesting of phantom unit our general partner does not intend to settle these awards in cash.

During 2009 and 2010, the fair value of the grants issued were calculated based on a discounted cash flow (“DCF”) model, prepared by an independent third party in October 2009, using a DCF analysis. This model included certain market assumptions related to future throughput volumes, projected fees and/or prices, expected costs of sales and direct operating costs and risk adjusted discount rates. The initial valuation was prepared in October of 2009 and the Company assessed the adequacy of that valuation on each grant date subsequent to the initial fair value calculation to determine if events or circumstances had occurred that would cause that valuation to become less relevant, noting none. Therefore, the Company maintained the $10 valuation throughout 2009 and 2010.

The following table summarizes our unit-based awards for each of the periods indicated, in units:


	Period Ended		Year Ended
	December 31,		December 31,
	2009		2010

Outstanding at beginning of period		—		361,052
Granted		361,052		153,368
Converted		—		(90,263	)

Outstanding at end of period		361,052		424,157

Grant date fair value per share	$	10.0	$	10.0

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at each balance sheet date. Compensation costs related to these awards during 2009 and 2010 was $0.2 million and $1.2 million, respectively, which is classified in selling, general and administrative expenses in the consolidated statement of operations and partners’ capital on the consolidated balance sheet.

The total compensation cost related to nonvested awards not yet recognized on December 31, 2009 and 2010 was $3.5 million and $3.9 million, respectively, and the weighted average period over which this cost is expected to be recognized is approximately 2 years.


15.	Post-Employment Benefits

Post-Employment Benefits other than Pensions

As a result of our acquisition from Enbridge, the sponsorship of the AlaTenn VEBA plans were transferred from Enbridge to us effective November 1, 2009. Accordingly, we sponsor a contributory postretirement plan that provides medical, dental and life insurance benefits for qualifying U.S. retired employees (referred to as the “OPEB Plan”).

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The tables below detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability of the OPEB Plan using the accrual method.


	OPEB Plan
	2009			2010
	(in thousands)

Change In Benefit Obligation
Obligation assumed from the acquisition from Enbridge	$	771		$	734
Service cost		2			10
Interest cost		7			43
Actuarial (gain) loss		(44	)		112
Benefits paid		(2	)		(30	)

Benefit obligation, December 31	$	734		$	869

Change In Plan Assets
Plan assets acquired from Enbridge	$	1,165		$	1,174
Actual return on plan assets		11			61
Employer’s contributions		—			113
Benefits paid		(2	)		(29	)

Fair value of plan assets, December 31	$	1,174		$	1,319

Funded Status
Funded status	$	394		$	440
Unrecognized actuarial gain		46			10

Prepaid (accrued) benefit cost, December 31	$	440		$	450

The amounts of plan net assets recognized in our consolidated balance sheets at December 31, 2009 and December 31, 2010 were as follows:


	OPEB Plan
	2009		2010
	(in thousands)

Other assets, net	$	440	$	450

	$	440	$	450

The amounts included in accumulated other comprehensive income that have not yet been recognized as components of net periodic benefit expense are $46,000 and $56,000 as of December 31, 2009 and 2010, respectively.

The accumulated benefit obligation for the OPEB Plan at December 31, 2009 and December 31, 2010 was $0.7 million and $0.9 million, respectively.

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Economic Assumptions

The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:


	OPEB Plan
	2009			2010

Discount rate		6.00	%		5.50	%
Expected return on plan assets		4.50	%		4.50	%

A one percent increase in the assumed medical and dental care trend rate would result in an increase of $0.1 million in the accumulated post-employment benefit obligations. A one percent decrease in the assumed medical and dental care trend rate would result in a decrease of $0.1 million in the accumulated post-employment benefit obligations.

The above table reflects the expected long-term rates of return on assets of the OPEB Plan on a weighted-average basis. The overall expected rates of return are based on the asset allocation targets with estimates for returns on equity and debt securities based on long term expectations. We believe this rate approximates the return we will achieve over the long-term on the assets of our plans. Historically, we have used a discount rate that corresponds to one or more high quality corporate bond indices as an estimate of our expected long-term rate of return on plan assets for our OPEB Plan assets. For 2009 and 2010 we selected the discount rate using the Citigroup Pension Discount Curve, or CPDC. The CPDC spot rates represent the equivalent yield on high-quality, zero-coupon bonds for specific maturities. These rates are used to develop a single, equivalent discount rate based on the OPEB Plan’s expected future cash flows.

Expected Future Benefit Payments

The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan:


	Gross Benefit
	Payments
For the year ending	OPEB Plan
	(in thousands)

2011	$	56
2012		56
2013		55
2014		55
2015		55
Five years thereafter		235

The expected future benefit payments are based upon the same assumptions used to measure the projected benefit obligations of the OPEB Plan including benefits associated with future employee service.

Expected Contributions to the Plans

We expect to make contributions to the OPEB Plan for the year ending December 31, 2011 of $0.1 million.

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Plan Assets

The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, are as follows:


	OPEB Plan
	2009			2010

Fixed income(a)		76.7	%		70.7	%
Cash and short-term assets(b)		23.3	%		29.3	%

Total		100.0	%		100.0	%


(a)		United States government securities, municipal corporate bonds and notes and as set backed securities.

(b)		Cash and securities with maturities of one year or less.


16.	Commitments and Contingencies

Future noncancelable commitments related to certain contractual obligations are presented below:


	Payments Due by Period (in thousands)
	Total		2011		2012		2013		2014		2015		Thereafter

Operating leases and service contract	$	2,057	$	580	$	405	$	342	$	351	$	349	$	30
ARO		8,340		914		—		—		—		—		7,426

Total	$	10,397	$	1,494	$	405	$	342	$	351	$	349	$	7,456

Total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:


	Period from
	August 20, 2009
	(Inception Date)
	to		Year Ended
	December 31,		December 31,
	2009		2010
	(in thousands)

Operating leases	$	60	$	757
ARO		—		25

	$	60	$	782


17.	Related-Party Transactions

F-47

partner does not record any profit or margin for the administrative and operational services charged to us. During the period and year ended December 31, 2009 and 2010, administrative and operational services expenses of $0.9 million and $0.9 million were allocated to us by our general partner.

We have entered into an advisory services agreement with American Infrastructure MLP Management, L.L.C., American Infrastructure MLP PE Management, L.L.C., and American Infrastructure MLP Associates Management, L.L.C., as the advisors. The agreement provides that we pay $0.3 million in 2010 and annual fees of $0.3 million plus annual increases in proportion to the increase in budgeted gross revenues thereafter. In exchange, the advisors have agreed to provide us services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services. For the period and year ended December 31, 2009 and 2010, less than $0.1 million and $0.3 million, respectively, had been recorded to selling, general and administrative expenses under this agreement.


18.	Reporting Segments

Our operations are located in the United States and are organized into two reporting segments: (1) Gathering and Processing; and (2) Transmission

Gathering and Processing

Transmission

F-48

The following tables set forth our segment information:


			Gathering
			and
	Transmission		Processing		Total
	(in thousands)

Period from August 20, 2009 (Inception date) to December 31, 2009
Total revenue	$	4,976	$	27,857	$	32,833
Segment gross margin(a)	$	2,542	$	3,698	$	6,240
Direct operating expenses						1,594
Selling, general and administrative expenses						1,346
One-time transaction costs						6,404
Depreciation expense						2,978
Interest expense						910

Net income (loss)					$	(6,992	)


			Gathering
			and
	Transmission		Processing		Total
	(in thousands)

Year ended December 31, 2010
Total revenue(b)	$	53,485	$	158,455	$	211,940
Segment gross margin(a)(b)	$	13,524	$	24,595	$	38,119
Direct operating expenses						12,187
Selling, general and administrative expenses						8,854
One-time transaction costs						303
Depreciation expense						20,013
Interest expense						5,406

Net income (loss)					$	(8,644	)


(a)		Segment gross margin for our Gathering and Processing segment consists of total revenue, including commodity derivative activity, less purchases of natural gas, NGLs and condensate. Segment gross margin for our Transmission segment consists of total revenue, less purchases of natural gas. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(b)		Noncash derivative mark-to-market is included in total revenue and segment gross margin in our Gathering and Processing segment.

Asset information including capital expenditures, by segment is not included in reports used by our management in its monitoring of performance and therefore, is not disclosed.

F-49

For the purposes of our Transmission segment, for the period ended December 31, 2009 and the year ended December 31, 2010, Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented significant customers, each representing more than 10% of our segment revenue in this segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented $3.0 million, $0.1 million and $0.9 million of segment revenue for the period ended 2009 and $16.6 million, $22.9 million and $5.1 million for the year ended 2010, respectively.

For the purposes of our Gathering and Processing segment, for the period ended December 31, 2009 and the year ended December 31, 2010, Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented significant customers, each representing more than 10% of our segment revenue in this segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented $14.7 million, $5.0 million and $3.1 million of segment revenue for the period ended 2009 and $47.3 million, $53.4 million and $16.4 million for the year ended 2010, respectively.


19.	Net Income (Loss) per Limited and General Partner Unit

F-50

We determined basic and diluted net income per general partner unit and limited partner unit as follows:


	For the
	Period from
	August 20, 2009
	(Inception Date)			For The
	to			Year Ended
	December 31,			December 31,
	2009			2010
	(in thousands, except per unit amounts)

Net loss attributable to general partner and limited partners	$	(6,992	)	$	(8,644	)
Weighted average general partner and limited partner units outstanding(a)		4,596			10,711
Earnings per general partner and limited partner unit (basic and diluted)	$	(1.52	)	$	(.81	)
Net loss attributable to limited partners	$	(6,852	)	$	(8,471	)
Weighted average limited partner units outstanding(a)		4,507			10,506
Earnings per limited partner unit (basic and diluted)	$	(1.52	)	$	(.81	)
Net loss attributable to general partner	$	(140	)	$	(173	)
Weighted average general partner units outstanding		89			205
Earnings per general partner unit (basic and diluted)	$	(1.58	)	$	(.84	)


(a)		Includes unvested phantom units, which are considered participating securities, of 361,052 and 424,157 as of December 31, 2009 and 2010, respectively.


20.	Subsequent Events

The Partnership has evaluated subsequent events through March 30, 2011.

On February 11, 2011, the Board of Directors of our general partner approved a distribution in the amount of $3.8 million, consisting of payments of $3.6 million to the limited partners, $0.1 million to the general partner and $0.1 million in DER payments.

On March 1, 2011, the Compensation Committee of the Board of Directors of our general partner approved the award of a total of 40,000 phantom units to certain employees under the Partnership LTIP program. The units vest over four years and do not contain distribution equivalent rights.

F-51

Report of Independent Registered Public Accounting Firm

To the Board of Directors of the General Partner of

American Midstream Partners, LP

We have audited the accompanying combined balance sheets of American Midstream Partners Predecessor (the Predecessor) as of December 31, 2008 and October 31, 2009, and the related combined statements of operations, of changes in group equity and of cash flows for the year ended December 31, 2008 and the ten-month period ended October 31, 2009. These financial statements are the responsibility of the management of American Midstream Partners, LP. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor at December 31, 2008 and October 31, 2009, and the results of their operations and their cash flows for the year ended December 31, 2008 and the ten-month period ended October 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 11 to the financial statements, the financial results contain significant transactions with related parties.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 30, 2011

F-52

American Midstream Partners Predecessor

Combined Balance Sheets

December 31, 2008 and October 31, 2009


	December 31,		October 31,
	2008		2009
	(in thousands)

Assets
Current assets
Cash and cash equivalents	$	421	$	149
Trade accounts receivable, net		1,411		248
Unbilled revenue		8,121		8,508
Due from affiliates		20,635		33,779
Notes receivable — affiliates		26,872		—
Other current assets		2,314		1,668

Total current assets		59,774		44,352
Property, plant and equipment, net		216,903		205,126
Other assets		565		684

Total assets	$	277,242	$	250,162

Liabilities and Group Equity
Current liabilities
Accounts payable	$	273	$	1,515
Accrued gas purchases		19,688		11,575
Notes payable — affiliate		39,339		—
Accrued expenses and other current liabilities		3,538		2,616

Total current liabilities		62,838		15,706
Other liabilities		2,605		2,864
Long-term debt		60,000		—

Total liabilities		125,443		18,570
Commitments and contingencies (see Note 10)
Group equity		151,799		231,592

Total liabilities and group equity	$	277,242	$	250,162

The accompanying notes are an integral part of these combined financial statements.

F-53

American Midstream Partners Predecessor

Combined Statements of Cash Flows
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009


	Year Ended			Period Ended
	December 31,			October 31,
	2008			2009
	(in thousands)

Cash flows from operating activities
Net income (loss)	$	2,728		$	(5,337	)
Adjustments to reconcile change in net assets to net cash provided by operating activities
Depreciation expense		13,481			12,630
Changes in operating assets and liabilities
Accounts receivable		1,102			1,163
Unbilled revenue		3,009			(387	)
Due from affiliates		8,262			(13,144	)
Notes receivable from affiliates		(4,400	)		26,872
Other current assets		(1,755	)		646
Other assets		(156	)		(320	)
Accounts payable		(807	)		1,242
Accrued gas purchase		(1,662	)		(8,113	)
Accrued expenses and other current liabilities		(1,761	)		(922	)
Other liabilities		114			259

Net cash provided by operating activities		18,155			14,589

Cash flows from investing activities
Additions to property, plant and equipment		(10,486	)		(853	)

Net cash (used in) investing activities		(10,486	)		(853	)

Cash flows from financing activities
Contributions from parent		10,500			111,103
Distributions to parent		(7,245	)		(25,772	)
Repayments of notes to affiliates		(11,184	)		(39,339	)
Repayments of long term debt		—			(60,000	)

Net cash (used in) financing activities		(7,929	)		(14,008	)

Net (decrease) increase in cash and cash equivalents		(260	)		(272	)
Cash and cash equivalents
Beginning of period		681			421

End of period	$	421		$	149

Supplemental cash flow information
Interest payments	$	325		$	132

The accompanying notes are an integral part of these combined financial statements.

F-56

American Midstream Partners Predecessor

Notes to Combined Financial Statements
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009


1.	Summary of Significant Accounting Policies

Nature of Business

These financial statements of American Midstream Partners Predecessor (the “Predecessor”) have been prepared in connection with the proposed initial public offering (the “Offering”) of limited partner units in America Midstream Partners, LP (the “Partnership”), which was formed in Delaware on August 20, 2009. The Partnership acquired certain natural gas pipeline and processing businesses from Enbridge Energy Partners, LP (“Enbridge”) in November 2009, as described below.

On October 2, 2009, Enbridge Midcoast Energy, L.P. (the “Parent”), a wholly-owned subsidiary of Enbridge entered into a purchase and sale agreement with American Midstream, LLC, a wholly owned subsidiary of the Partnership, for the sale of certain pipeline entities (collectively the “Entities”). The sale was effective as of November 1, 2009. In conjunction with the close of the transaction, the Parent received cash consideration of $150,817,898, excluding the subsequent settlement for working capital as provided in the purchase and sale agreement.

The Entities were as follows:

Enbridge Pipelines — Alabama Intrastate L.L.C.

Enbridge Pipelines — Bamagas Intrastate L.L.C.

Enbridge Pipelines — Tennessee River L.L.C.

Enbridge Pipelines — Mississippi L.L.C.

Enbridge Pipelines — Midla L.L.C.

Enbridge Pipelines — Alabama Gathering L.L.C.

Enbridge Pipelines — AlaTenn L.L.C.

Midcoast Holdings No. One L.L.C.

Mid Louisiana Gas Transmission L.L.C.

Enbridge Offshore Pipelines — Seacrest, LP

Enbridge Pipelines — SIGCO Intrastate L.L.C.

Enbridge Pipelines — Louisiana Intrastate, L.L.C.

These combined financial statements represent the financial position, results of operations, changes in group equity and cash flows of the Predecessor, have been prepared from the separate records maintained by Enbridge and include allocations of certain Enbridge corporate expenses. Management of the Partnership believes that the assumptions and estimates used in preparation of the combined financial statements are reasonable. However, the combined financial statements may not necessarily reflect what the Predecessor’s financial position, results of operations or cash flows would have been had it been a stand-alone entity during the periods presented. Because of the nature of these combined financial statements, the Parent’s net investment in the Entities, including amounts due to the Parent are shown as “group equity”.

The Predecessor’s interstate natural gas pipeline assets transport natural gas through Federal Energy Regulatory Commission (the “FERC”) regulated interstate natural gas pipelines in Louisiana, Mississippi, Alabama and Tennessee. The interstate pipelines include:


	•	Enbridge Pipelines — Midla L.L.C., which owns and operates approximately 370 miles of interstate pipeline that runs from the Monroe gas field in northern Louisiana south through Mississippi to Baton Rouge, Louisiana.

	•	Enbridge Pipelines — AlaTenn L.L.C., which owns and operates approximately 295 miles of interstate pipeline that runs through the Tennessee River Valley from Selmer, Tennessee to Huntsville, Alabama and serves an eight county area in Alabama, Mississippi, and Tennessee.

F-57

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

Events and transactions subsequent to the balance sheet date have been evaluated through March 30, 2011, the date these combined financial statements were issued.

Basis of Presentation and Use of Estimates

The combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) on the basis of the Parent’s historical ownership of the Predecessor. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying combined financial statements.

Use of Estimates

When preparing financial statements in conformity with accounting principles generally accepted in the United States of America, the Predecessor must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.

Accounting for Regulated Operations

Certain of the Predecessor’s natural gas pipelines are subject to regulation by the FERC. The FERC exercises statutory authority over matters such as construction, transportation rates the Predecessor charges and the Predecessor’s underlying accounting practices, and ratemaking agreements with customers. Accordingly, the Predecessor records costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated entity. Also, the Predecessor records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for the Predecessor’s regulated entities. As of December 31, 2008 and October 31, 2009, the Predecessor had no significant regulatory assets or liabilities.

Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas

The Predecessor recognizes revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectibility is reasonably assured. The Predecessor records revenue and cost of product sold on the gross basis for those transactions where the Predecessor acted as the principal and takes title to natural gas, natural gas liquids (“NGLs”) or condensate that are purchased for resale. When the Predecessors’ customers pay it a fee for providing a service such as gathering, treating or transportation the

F-58

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

Predecessor records those fees separately in revenues. For the year and period ended December 31, 2008 and October 31 2009, respectively, the Predecessor had the following revenues by category:


	Year Ended		Period Ended
	December 31,		October 31,
	2008		2009
	(in thousands)

Revenue
Transportation — firm	$	15,780	$	10,616
Transportation — interruptible		2,331		1,662
Sales of natural gas, NGLs and condensate		348,034		129,673
Other		203		1,181

	$	366,348	$	143,132

The Predecessor derives revenue in its business from the following types of arrangements:


	•	*Fee-Based.* Under these arrangements, the Predecessor generally is paid a fixed cash fee for gathering and transporting natural gas.

	•	*Percent-of-Proceeds, or POP.* Under these arrangements, the Predecessor generally gathers raw natural gas from producers at the wellhead or other supply points, transports it through the Predecessor’s gathering system, processes it and sells the residue natural gas and NGLs at market prices. Where the Predecessor provides processing services at the processing plants that it owns, or obtains processing services for its own account under its elective processing arrangements, the Predecessor typically retains and sells a percentage of the residue natural gas and resulting NGLs.

	•	*Fixed-Margin.* Under these arrangements, the Predecessor purchases natural gas from producers or suppliers at receipt points on the Predecessor’s systems at an index price less a fixed transportation fee and simultaneously sells an identical volume of natural gas at delivery points on the Predecessor’s systems at the same, undiscounted index price.

	•	*Firm Transportation.* The Predecessor’s obligation to provide firm transportation service means that the Predecessor is obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on the Predecessor’s part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by the Predecessor.

	•	*Interruptible Transportation.* The Predecessor’s obligation to provide interruptible transportation service means that the Predecessor is only obligated to transport natural gas nominated by the shipper to the extent that the Predecessor was available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped.

Estimates of Revenue and Cost of Natural Gas

The Predecessor must estimate its current month revenue and cost of gas to permit the timely preparation of the combined financial statements. The Predecessor generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data prior to the preparation of the combined financial statements. As a result, the Predecessor records an estimate each month for its operating revenues and cost of natural gas based on the best available volume and price data for natural gas delivered and received, along with a true-up of the prior month’s estimate to equal the prior month’s actual data. As a result there is one month of estimated data reported in the Predecessor’s operating

F-59

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

revenues and cost of natural gas for each of the year ended December 31, 2008. The operating revenues and cost of natural gas for the ten months ended October 31, 2009 reflects actual invoiced amounts.

Cash and Cash Equivalents

The Predecessor considers all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.

Allowance for Doubtful Accounts

The Predecessor establishes provisions for losses on accounts receivable when it determines that it will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2008 and October 31, 2009 the Predecessor has recorded, $170,393 and $985,956, respectively, in allowances for doubtful accounts.

Inventory

Inventory includes product inventory and material and supplies inventory. The Entities records all product inventories at the lower of its cost, as determined on a weighted average basis, or market value. The product inventory consists of liquid hydrocarbons and natural gas. Upon disposition, product inventory is recorded to “Purchases of natural gas, NGL’s and Condensate” at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.

Operational Balancing Agreements and Natural Gas Imbalances

To facilitate deliveries of natural gas and provide for operational flexibility, the Predecessor has operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through receipt or delivery of natural gas. Natural gas imbalances are recorded as gas imbalances and classified within “Other currents assets” on the Predecessor’s combined balance sheets using the posted index prices, which approximate market rates, or the Predecessor’s weighted average cost of natural gas.

Property, Plant and Equipment

The Predecessor capitalizes expenditures related to property, plant and equipment that have a useful life greater than one year for 1) assets purchased or constructed; 2) existing assets that are replaced, improved, or the useful lives of which have been extended; and 3) all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

The Predecessor records property, plant and equipment at its original cost, which the Predecessor depreciates on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives. The Predecessor’s determination of the useful lives of property, plant and equipment requires the Predecessor to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by the Predecessor’s assets, normal wear and tear of the facilities, and the extent and frequency of maintenance

F-60

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

programs. The Predecessor records depreciation using the group method of depreciation which is commonly used by pipelines, utilities and similar entities.

Impairment of Long Lived Assets

The Predecessor evaluates the recoverability of its property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal and other factors indicate the Predecessor may not recover the carrying amount of the assets. The Predecessor continually monitors its businesses, the market and business environment to identify indicators that could suggest an asset may not be recoverable. The Predecessor evaluates the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require the Predecessor to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. The Predecessor recognizes an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires the Predecessor to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes the Predecessor makes to these projections and assumptions could result in significant revisions to the Predecessor’s evaluation of the recoverability of its property, plant and equipment and the recognition of an impairment loss in its consolidated statements of income. No impairment losses were recognized during the year ended and period ended December 31, 2008 and October 31, 2009, respectively.

The Predecessor assess its long-lived assets for impairment using authoritative guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Fair values, for the purposes of the impairment test, are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

Examples of long-lived asset impairment indicators include:


	•	A significant decrease in the market price of a long-lived asset or group;

	•	A significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;

	•	A significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;

	•	An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;

	•	A current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long lived asset or asset group; and

	•	A current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

Income Taxes

All of the entities of the Entities are disregarded for U.S. federal income tax purposes or for the majority of states that impose an income tax. The Entities’ income tax expense results from the enactment of state

F-61

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

income tax laws by the State of Texas that apply to entities organized as partnerships. The Texas margin tax is computed on our modified gross margin and was not significant for each of the year ended December 31, 2008 and the period ended October 31, 2009. The Predecessor has determined these taxes to be income taxes as set forth in the authoritative accounting guidance.

Commitments, Contingencies and Environmental Liabilities

The Predecessor expenses or capitalizes, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. The Predecessor expenses amounts it incurs for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. It records liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of inflation and other factors. These amounts also consider the Predecessor’s prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Its estimates are subject to revision in future periods based on actual costs or new information. The Predecessor evaluates recoveries from insurance coverage separately from the liability and, when recovery is probable, it records and reports an asset separately from the associated liability in its combined financial statements.

The Predecessor recognizes liabilities for other commitments and contingencies when, after fully analyzing the available information, determines it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, it accrues the most likely amount, or if no amount is more likely than another, it accrues the minimum of the range of probable loss. The Predecessor expenses legal costs associated with loss contingencies as such costs are incurred.

Asset Retirement Obligations (“AROs”)

AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, the Predecessor records an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The Predecessor depreciates the capitalized ARO using the straight-line method over the period during which the related long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the Predecessor revises the ARO to reflect the passage of time or revisions to the amounts of estimated cash flows or their timing.

Group Equity

The group equity balance represents a net balance reflecting the Parent’s initial investment in Entities and subsequent adjustments resulting from the operations of the Entities and various transactions between the Parent and the Entities. Other transactions affecting the group equity include general, administrative and overhead costs incurred by the Parent that are allocated to the Entities. There are no terms of settlement or interest charges associated with the group equity balance.


2.	Concentration of Credit Risk and Trade Accounts Receivable

The Predecessor’s primary market areas are located in the United States along the Gulf Coast and in the Southeast. The Predecessor has a concentration of trade receivable balances due from companies engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of

F-62

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. The Predecessor’s customers’ historical financial and operating information is analyzed prior to extending credit. The Predecessor manages its exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions, the Predecessor may request letters of credit, prepayments or guarantees. The Predecessor maintains allowances for potentially uncollectible accounts receivable.

As of December 31, 2008, ConocoPhillips Corporation and Dow Hydrocarbons and Resources were significant customers, representing at least 10% of the Predecessor’s combined revenue, accounting for $40.5 million and $44.2 million, respectively, of the Predecessor’s combined revenue in the combined statement of operations for the year then ended. As of October 31, 2009, ConocoPhillips Corporation and Enbridge Marketing were significant customers, representing at least 10% of the Predecessor’s combined revenue, accounting for $18.5 million and $40.4 million, respectively, of the Predecessor’s combined revenue in the consolidated statement of operations for the period then ended.


3.	Other Current Assets

Other current assets as of December 31, 2008 and October 31, 2009 were as follows:


	2008		2009
	(in thousands)

Gas imbalance	$	76	$	530
Inventory		2,045		180
Other receivables		42		773
Regulatory deferrals		74		88
Other prepaid amounts		77		97

	$	2,314	$	1,668


4.	Property, Plant and Equipment, Net

Property, plant and equipment, net, as of December 31, 2008 and October 31, 2009 were as follows:


	Useful Life		2008			2009
			(in thousands)

Land		—	$	433		$	433
Rights-of-way		40		26,628			26,633
Pipelines		40		180,470			181,096
Compressors, meters and other operating equipment		20		25,821			28,182
Vehicles, office furniture and equipment		5		6,847			6,937
Processing and treating plants		40		30,009			32,306
Construction in progress		—		7,222			1,110

Total property, plant and equipment				277,430			276,697
Accumulated depreciation				(60,527	)		(71,571	)

Property, plant and equipment, net			$	216,903		$	205,126

For regulatory purposes, the Predecessor’s uses FERC-approved depreciation rates to depreciate the regulated pipeline assets of Enbridge Pipelines — Midla L.L.C. and Enbridge Pipelines — AlaTenn L.L.C. Of

F-63

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

the gross property, plant and equipment balances at December 31, 2008 and October 31, 2009 $102.4 million and $101.8 million, respectively, related to regulated assets.


5.	Asset Retirement Obligations (“AROs”)

No assets are legally restricted for purposes of settling the Predecessor’s AROs for the year ended December 31, 2008 and the period ended October 31, 2009. Following is a reconciliation of the beginning and ending aggregate carrying amount of the Predecessor’s ARO liabilities for the year ended December 31, 2008 and the period ended October 31, 2009:


	2008		2009
	(in thousands)

Balance at beginning of period	$	1,926	$	2,006
Accretion expense		80		108

Balance at end of period	$	2,006	$	2,114


6.	Other Assets, net

Other assets, net, as of December 31, 2008 and October 31, 2009 were as follows:


	2008		2009
	(in thousands)

Other post-retirement benefit plan assets, net	$	258	$	395
Deferred charges, net		128		123
Other		179		166

	$	565	$	684


7.	Accrued Expenses and Other Current Liabilities

Other current liabilities as of December 31, 2008 and October 31, 2009 were as follows:


	2008		2009
	(in thousands)

Accrued expenses	$	2,972	$	1,109
Property taxes payable		500		1,103
Environmental reserves		45		380
Deferred revenue		21		24

	$	3,538	$	2,616


8.	Notes Payable — Affiliate

Short-term Borrowings

Throughout 2008 and 2009, the Entities periodically entered into certain short-term demand promissory notes with Enbridge Midcoast Limited Holdings, L.L.C. (“EMLH”), a wholly owned subsidiary of the Parent. At December 31, 2008 and October 31, 2009, the outstanding balances of short-term borrowings were $39.3 and $0 million, respectively. Prior to March 2008, interest on these borrowings is charged at 130% of the applicable federal rate as published by the U.S. Treasury (“AFR”). Subsequent to March 2008, interest on these borrowings is charged at the greater of i) the London Interbank Offering Rate (“LIBOR”), plus 100 basis

F-64

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

points or ii) 130% of the published AFR. The weighted average interest rate on outstanding borrowings at October 31, 2009 and December 31, 2008 was 1.36% and 3.59%, respectively.

Long-term Borrowings

During 2004, the Entities entered into a series of promissory notes with EMLH, totaling $65 million, with repayment of the principal balance of these notes due on November 26, 2014 (“the Notes”). Interest on the Notes was paid semiannually in May and November of each year. The capitalized deferred costs of approximately $0.1 million and $0.1 million as of December 31, 2008 and October 31, 2009 associated with the issuance of this debt are amortized over the ten year life of the Notes.

Debt Extinguishment

On October 29, 2009, the Parent made a capital contribution of $111.1 million to the Entities. A portion of the proceeds of this contribution were used by the Entities to repay in full the short-term borrowings and the Notes outstanding with EMLH.

Financial Covenants

There were no restrictive covenants associated with either the short-term borrowings or the Notes.


9.	Post-Employment Benefits

Post-Employment Benefits Other Than Pensions

We sponsor a contributory postretirement plan that provides medical, dental and life insurance benefits for qualifying U.S. retired employees (referred to as the “OPEB Plan”).

The tables below detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability of the OPEB Plan using the accrual method.


	OPEB Plan
	2008			2009
	(in thousands)

Change in benefit obligation
Benefit obligation, January 1	$	642		$	741
Service cost		11			8
Interest cost		46			36
Actuarial (gain) loss		71			10
Benefits paid		(29	)		(24	)

Benefit obligation, December 31, and October 31	$	741		$	771

F-65

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009


	OPEB Plan
	2008			2009
	(in thousands)

Change in plan assets
Fair value of plan assets, January 1	$	987		$	999
Actual return on plan assets		(72	)		123
Employer’s contributions		113			68
Participant contributions		—			—
Benefits paid		(29	)		(24	)

Fair value of plan assets, December 31 and October 31	$	999		$	1,166


	OPEB Plan
	2008			2009
	(in thousands)

Funded status
Funded status	$	258		$	395
Unrecognized actuarial gain		(339	)		(138	)

Prepaid (accrued) benefit cost, December 31 and October 31	$	(81	)	$	257

The amounts of plan assets and liabilities recognized in our statements of financial position at December 31, 2008 and October 31, 2009 are as follows:


	OPEB Plan
	2008		2009
	(in thousands)

Long term other assets	$	258	$	395

	$	258	$	395

The amounts included in accumulated other comprehensive income that have not yet been recognized as components of net periodic benefit expense are $339,000 and $138,000 as of December 31, 2008 and October 31, 2009, respectively.

Economic Assumptions

The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:


	OPEB Plan
	2008		2009

Discount rate		6.00%		5.70%
Expected return on plan assets		4.50%		6.00%
Rate of compensation increase		5%		0%
Health care trend		Grade 9% to 5% over 5 years		Grade 9% to 5% over 5 years

F-66

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

medical and dental care trend rate would result in a decrease of $0.1 million in the accumulated post-employment benefit obligations.

The above table reflects the expected long-term rates of return on assets of the OPEB Plan on a weighted-average basis. The overall expected rates of return are based on the asset allocation targets with estimates for returns on equity and debt securities based on long term expectations. We believe this rate approximates the return we will achieve over the long-term on the assets of our plans. Historically, we have used a discount rate that corresponds to one or more high quality corporate bond indices as an estimate of our expected long-term rate of return on plan assets for our OPEB Plan assets. For 2008 and 2009 we selected the discount rate using the Citigroup Pension Discount Curve, or CPDC. The CPDC spot rates represent the equivalent yield on high-quality, zero-coupon bonds for specific maturities. These rates are used to develop a single, equivalent discount rate based on the OPEB Plan’s expected future cash flows.

Expected Future Benefit Payments

The following table presents the benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five years thereafter by the OPEB Plan:


	Gross Benefit
	Payments
For the year ending	OPEB Plan
	(in thousands)

2011	$	56
2012		56
2013		55
2014		55
2015		55
Five years thereafter		235

The expected future benefit payments are based upon the same assumptions used to measure the projected benefit obligations of the OPEB Plan including benefits associated with future employee service.

Expected Contributions to the Plans

We expect to make contributions to the OPEB Plan for the year ending December 31, 2010 of $0.1 million.

Plan Assets

The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, are as follows:


	OPEB Plan
	2008		2009

Fixed income(a)		77.0%		77.0%
Cash and short-term assets(b)		23.0%		23.0%

		100.0%		100.0%


(a)		United States government securities, corporate bonds and notes and asset-backed securities.

(b)		Cash and securities with maturities of one year or less.

F-67

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009


10.	Commitments and Contingencies

The Predecessor is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipeline operations, and the Predecessor could, at times, be subject to environmental cleanup and enforcement actions. The Predecessor attempts to manage this environmental risk through appropriate environmental policies and practices to minimize any impact the Predecessor’s operations may have on the environment.


11.	Related Party Transactions

The Predecessor was wholly owned by the Parent and its subsidiaries. The Parent has allocated certain overhead costs associated with general and administrative services, including executive management, accounting, information services, engineering, and human resources support to the Predecessor. These overhead costs were allocated based primarily on a percentage of revenue, which management of the Partnership believes is reasonable.

Revenues, Purchases and Cost Allocations

The Predecessor recorded operating revenues to Enbridge affiliates for natural gas gathering, treating, processing, marketing and transportation services. Included in the Predecessor’s results for the year ended December 31, 2008 and period ended October 31, 2009, are operating revenues $202.9 of million and $73.9 million, respectively, related to these transactions.

The Predecessor also purchased natural gas from Enbridge affiliates for sale to third-parties at market prices on the date of purchase. Included in the Predecessor’s results for the year ended December 31, 2008 and period ended October 31, 2009, are costs for natural gas purchases of $0.1 million and $0.9 million, respectively, related to these purchases.

The Predecessor incurred expenses related to managerial, administrative, operational and director services provided by the Parent and its affiliates and the ultimate parent, Enbridge pursuant to service agreements (referred to as “Enbridge cost allocations”).

The Enbridge cost allocations were charged based on a combination of fixed monthly fees for operations and allocations for overhead costs, which were based primarily on the direct salaries of the employees by department and by entity. The allocation method has been consistently applied in the statements of operations.

The total amount charged to the Predecessor for Enbridge cost allocations for the year ended December 31, 2008 and period ended October 31, 2009 was $7.9 million and $6.7 million, respectively.

At December 31, 2008 and October 31, 2009, the Predecessor had affiliate receivables of $21.0 million and $34.4 million, respectively related to these transactions.

Financing Transactions with Affiliates

Demand Notes Receivable and Notes Payable

At December 31, 2008 and October 31, 2009, the Predecessor had affiliate notes receivable of $26.9 and $0 million, respectively, and affiliate notes payable of $39.3 million and $0 million, respectively. For the twelve months ended December 31, 2008 and ten months ended October 31, 2009, the Predecessor had interest income of $0.8 million and $0.4 million, respectively. Interest expense for the twelve months ended December 31, 2008 and ten months ended October 31, 2009 was $6.7 million and $4.1 million, respectively.

F-68

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009

Equity Transactions

For the twelve months ended December 31, 2008 and the ten months ended October 31, 2009, the Predecessor received contributions by the Parent of $10.5 million and $111.1 million, respectively, and paid distributions to the Parent of $7.3 million and $25.8 million, respectively.


12.	Reportable Segments

The Predecessor’s operations are located in the United States and are organized into two reporting segments: (1) Gathering and Processing; and (2) Transmission.

Gathering and Processing

The Predecessor’s Gathering and Processing segment provides “wellhead to market” services to producers of natural gas and oil, which include transporting raw natural gas from the wellhead through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs and selling or delivering pipeline quality natural gas and NGLs to various markets and pipeline systems.

Transmission

The Predecessor’s Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies, or LDCs, utilities and industrial, commercial and power generation customers.

These segments are monitored separately by American Midstream Partners, LP for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by the Predecessor to monitor the business of each segment.

The following tables set forth the Predecessor’s segment information:


			Gathering
			and
	Transmission		Processing		Total
	(in thousands)

Year ended December 31, 2008
Total revenue	$	16,487	$	349,861	$	366,348
Segment gross margin(a)	$	15,789	$	27,354	$	43,143
Direct operating expenses						13,423
Selling, general and administrative expenses						8,618
Depreciation expense						13,481
Interest expense						5,747
Other (income) expense						(854	)

Net income					$	2,728

F-69

American Midstream Partners Predecessor

Notes to Combined Financial Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended October 31, 2009


			Gathering
			and
	Transmission		Processing		Total
	(in thousands)

Period ended October 31, 2009
Total revenue	$	10,175	$	132,957	$	143,132
Segment gross margin(a)	$	9,881	$	20,024	$	29,905
Direct operating expenses						10,331
Depreciation expense						8,577
Selling, general and administrative expense						12,630
Interest expense						3,728
Other (income) expense						(24	)

Net loss					$	(5,337	)


(a)		Segment gross margin for our Gathering and Processing segment consists of total revenue, less purchases of natural gas, propane and NGLs. Segment gross margin for our Transmission segment consists of total revenue, less purchases of natural gas. Gross margin consists of the sum of the segment gross margin amounts for each of these segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

Asset information by segment, including capital expenditures, is not included in reports used by management of American Midstream Partners, LP in its monitoring of performance and therefore, is not disclosed.

F-70

SECOND AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP OF
AMERICAN MIDSTREAM PARTNERS, LP

THIS SECOND AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF AMERICAN MIDSTREAM PARTNERS, LP dated as of July , 2011, is entered into by and between American Midstream GP, LLC, a Delaware limited liability company, as the General Partner, and AIM Midstream Holdings, LLC, a Delaware limited liability company (“AIM Midstream”), together with any other Persons who are now or become Partners in the Partnership or parties hereto as provided herein.

WHEREAS, the General Partner and the Limited Partners entered into that certain First Amended and Restated Agreement of Limited Partnership dated as of November 4, 2009 (the “First A/R Partnership Agreement”);

WHEREAS, in connection with the Initial Public Offering of Common Units (as such terms are hereinafter defined) by the Partnership, the General Partner deems it necessary and appropriate to amend and restate the First A/R Partnership Agreement to provide for certain amendments in connection with the Initial Public Offering; and

WHEREAS, pursuant to Article XIII of the First A/R Partnership Agreement, the First A/R Partnership Agreement may be amended upon approval by the General Partner, the holders of at least 90% of the Outstanding Units (as defined in the First A/R Partnership Agreement) voting as a single class, such approval having been duly obtained in accordance with the procedures set forth in the First A/R Partnership Agreement;

NOW, THEREFORE, the General Partner does hereby amend and restate the Second A/R Partnership Agreement to provide in its entirety as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the long-term operating capacity or operating income of the Partnership Group from the operating capacity or operating income of the Partnership Group existing immediately prior to such transaction.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the

A-1

Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period. With respect to a Disposed of Adjusted Property, the Additional Book Basis Derivative Items shall be the amount of Additional Book Basis taken into account in computing gain or loss from the disposition of such Disposed of Adjusted Property.

“Additional Limited Partner” means a Person admitted to the Partnership as a Limited Partner pursuant to Section 10.1(b) and who is shown as such on the books and records of the Partnership.

“Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each taxable period of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all losses and deductions that, as of the end of such taxable period, are reasonably expected to be allocated to such Partner in subsequent taxable periods under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such taxable period, are reasonably expected to be made to such Partner in subsequent taxable periods in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the taxable period in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of a Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Adjusted Operating Surplus” means, with respect to any period, (a) Operating Surplus generated with respect to such period, less (b) (i) any net increase in Working Capital Borrowings with respect to that period and (ii) any net decrease in cash reserves for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period, and plus (c) (i) any net decrease in Working Capital Borrowings with respect to that period, (ii) any net decrease made in subsequent periods in cash reserves for Operating Expenditures initially established with respect to such period to the extent such decrease results in a reduction in Adjusted Operating Surplus in subsequent periods pursuant to clause (b)(ii) above and (iii) any net increase in cash reserves for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Aggregate Quantity of IDR Reset Common Units” has the meaning assigned to such term in Section 5.11(a).

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“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution and in the case of an Adjusted Property, the fair market value of such Adjusted Property on the date of the revaluation event as described in Section 5.5(d), in both cases as determined by the General Partner.

“Agreement” means this Second Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, as it may be amended, supplemented or restated from time to time.

“AIM Midstream” means AIM Midstream Holdings, LLC, a Delaware limited liability company.

“American Midstream GP” means American Midstream GP, LLC, a Delaware limited liability company.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of:

(i) all cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of such Quarter; and

(ii) if the General Partner so determines, all or any portion of additional cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter;

(b) less the amount of any cash reserves (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) established by the General Partner to:

(i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures, for anticipated future credit needs of the Partnership Group and for refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing relating to FERC rate proceedings or rate proceedings under applicable state law, if any) subsequent to such Quarter;

(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject; or

(iii) provide funds for distributions under Section 6.4 or Section 6.5 in respect of any one or more of the next four Quarters;

provided, however, that the General Partner may not establish cash reserves pursuant to clause (iii) above if the effect of establishing such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; and, provided further, that disbursements made by a Group Member or

A-3

cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Board of Directors” means the board of directors of the General Partner.

“Book Basis Derivative Items” means any item of income, deduction, gain or loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of a Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Capital Contribution” means (i) any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions) or (ii) current distributions that a Partner is entitled to receive but otherwise waives.

“Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition (through an asset acquisition, merger, stock acquisition or other form of investment) of existing, or the construction of new or improvement or replacement of existing, capital assets (including gathering systems, compressors, processing plants, transmission lines and related or similar midstream assets) or (c) capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has, or after such capital contribution will have, an equity interest to fund such Group Member’s pro rata share of the cost of the addition or improvement to or the acquisition (through an asset acquisition, merger, stock acquisition or other form of investment) of existing, or the construction of new or replacement of existing, capital assets (including gathering systems, compressors, processing plants, transmission lines and related or similar midstream assets) by such Person, in each case if and to the extent such addition, improvement, acquisition, construction or replacement is made to increase the long-term operating capacity, or operating income of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the operating capacity or operating income of the Partnership Group or such Person, as the case may be, existing immediately prior to such addition, improvement, acquisition, construction or replacement.

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“Capital Surplus” has the meaning assigned to such term in Section 6.3(a).

“Carrying Value” means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such Contributed Property or Adjusted Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.5(d) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to the First A/R Partnership Agreement (if such certificate was issued on or after November 4, 2009, but prior to the date hereof) or substantially in the form of Exhibit A to this Agreement (if such certificate is issued on or after the date hereof), (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the General Partner, in each case issued by the Partnership evidencing ownership of one or more Common Units or (b) a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Interests.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“Citizenship Eligibility Trigger” has the meaning assigned to such term in Section 4.9(a)(ii).

“claim” (as used in Section 7.12(c)) has the meaning assigned to such term in Section 7.12(c).

“Closing Date” means November 4, 2009.

“Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange on which the respective Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the primary reporting system then in use in relation to such Limited Partner Interests of such class, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Combined Interest” has the meaning assigned to such term in Section 11.3(a).

“Commences Commercial Service” means the date a Capital Improvement is first put into or commences commercial service following completion of construction, acquisition, development and testing, as applicable.

“Commission” means the United States Securities and Exchange Commission or any successor agency having jurisdiction under the Securities Act.

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“Commodity Hedge Contract” means any commodity exchange, swap, forward, cap, floor, collar or other similar agreement or arrangement entered into for the purpose of hedging the Partnership Group’s exposure to fluctuations in the price of hydrocarbons or other commodities in their operations and not for speculative purposes.

“Common Unit” means a Partnership Interest representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not include a Subordinated Unit prior to its conversion into a Common Unit pursuant to the terms hereof.

“Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, as to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(b)(i).

“Conflicts Committee” means a committee of the Board of Directors composed of one or more Independent Directors.

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum resulting from adding together the Common Unit Arrearage as to an IPO Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(b)(ii) and the second sentence of Section 6.5 with respect to an IPO Common Unit (including any distributions to be made in respect of the last of such Quarters).

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

“Current Market Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former general partner from and after the effective date of any withdrawal or removal of such former general partner pursuant to Section 11.1 or Section 11.2.

“Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“Disposed of Adjusted Property” has the meaning ascribed to such term in Section 6.1(d)(xii)(B).

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“Eligibility Certificate” has the meaning assigned to such term in Section 4.9(b).

“Eligible Holder” means a Limited Partner whose (a) federal income tax status would not, in the determination of the General Partner, have the material adverse effect described in Section 4.9(a)(i) or (b) nationality, citizenship or other related status would not, in the determination of the General Partner, create a substantial risk of cancellation or forfeiture as described in Section 4.9(a)(ii).

“Estimated Incremental Quarterly Tax Amount” has the meaning assigned to such term in Section 6.9.

“Estimated Maintenance Capital Expenditures” means an estimate made in good faith by the Board of Directors (with the concurrence of the Conflicts Committee) of the average quarterly Maintenance Capital

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Expenditures that the Partnership will incur over the long term. The Board of Directors (with the concurrence of the Conflicts Committee) will be permitted to make such estimate in any manner it determines reasonable. The estimate will be made annually and whenever an event occurs that is likely to result in a material adjustment to the amount of Maintenance Capital Expenditures on a long term basis. The Partnership shall disclose to its Partners any change in the amount of Estimated Maintenance Capital Expenditures in its reports made in accordance with Section 8.3 to the extent not previously disclosed. Except as provided in the definition of Subordination Period, any adjustments to Estimated Maintenance Capital Expenditures shall be prospective only.

“Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

“Existing Credit Agreement” means the Revolving Credit and Term Loan Agreement, dated as of October 5, 2009, by and among the Operating Company, the other borrowers party thereto, Comerica Bank, as Administrative Agent, Co-Lead Arranger and Syndication Administrative Agent, BBVA Compass Bank, as Documentation Agent and Co-Lead Arranger, and the other lenders party thereto.

“Expansion Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements, and shall not include Maintenance Capital Expenditures or Investment Capital Expenditures. Expansion Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued, in each case, to finance the construction of a Capital Improvement and paid in respect of the period beginning on the date that the Group Member enters into a binding obligation to commence construction of a 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. Debt incurred or equity issued to fund such construction period interest payments or such construction period distributions on equity paid during such period, shall also be deemed to be debt incurred or equity issued, as the case may be, to finance the construction of a Capital Improvement. Expansion Capital Expenditures will include cash contributed by a Group Member to an entity of which such Group Member is, or after such contribution will be, directly or indirectly, an equity owner to be used by such entity for Acquisitions or Capital Improvements. Where capital expenditures are made in part for Expansion Capital Expenditures and in part for other purposes, the General Partner, with the concurrence of the Conflicts Committee, shall determine the allocation of such expenditures between Expansion Capital Expenditures and expenditures made for other purposes.

“FERC” means the Federal Energy Regulatory Commission, or successor to powers thereof.

“Final Subordinated Units” has the meaning assigned to such term in Section 6.1(d)(x)(A).

“First A/R Partnership Agreement” has the meaning assigned to such term in the recitals to this Agreement.

“First Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(D).

“First Target Distribution” means 115% of the Minimum Quarterly Distribution per Unit (or, with respect to the Quarter that includes the IPO Closing Date, it means the product of 115% of the Minimum Quarterly Distribution per Unit multiplied by a fraction, the numerator of which is the number of days in such Quarter after the IPO Closing Date, and the denominator of which is the total number of days in such Quarter), subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

“Fully Diluted Weighted Average Basis” means, when calculating the number of Outstanding Units for any period, a basis that includes (a) the weighted average number of Outstanding Units plus (b) all Partnership Interests and options, rights, warrants, phantom units and appreciation rights relating to an equity interest in the Partnership (i) that are convertible into or exercisable or exchangeable for Units or for which Units are issuable, in each case that are senior to or pari passu with the Subordinated Units, (ii) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (iii) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with

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administrative mechanics applicable to such conversion, exercise or exchange and (iv) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Weighted Average Basis when calculating whether the Subordination Period has ended or Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7, such Partnership Interests, options, rights, warrants and appreciation rights shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (x) the number of Units issuable upon such conversion, exercise or exchange and (y) the number of Units that such consideration would purchase at the Current Market Price.

“General Partner” means American Midstream GP and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it) that is evidenced by Notional General Partner Units and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s length transaction.

“Group” means a Person that with or through any of its Affiliates or Associates has any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Holder” as used in Section 7.12, has the meaning assigned to such term in Section 7.12(a).

“IDR Reset Common Unit” has the meaning assigned to such term in Section 5.11(a).

“IDR Reset Election” has the meaning assigned to such term in Section 5.11(a).

“Incentive Distribution Right” means a Limited Partner Interest issued to American Midstream GP, which Limited Partner Interest will confer upon the holder thereof only the rights and obligations specifically provided in this Agreement with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest). Notwithstanding anything to the contrary in this Agreement, the holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter except as may otherwise be required by law.

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“Incentive Distributions” means any amount of cash distributed to the holders of the Incentive Distribution Rights (in such capacity, but not in any other capacity) pursuant to Section 6.4.

“Incremental Income Taxes” has the meaning assigned to such term in Section 6.9.

“Indemnified Persons” has the meaning assigned to such term in Section 7.12(c).

“Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of another Person owing a fiduciary duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, (f) any Person who controls a General Partner or Departing General Partner and (g) any Person the General Partner designates as an Indemnitee for purposes of this Agreement.

“Independent Director” means any director that (a) is not a security holder, officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner, (c) is not a holder of any ownership interest in the Partnership Group other than Common Units and awards that may be granted to such director under the Long Term Incentive Plan (or similar plan implemented by the General Partner or the Partnership) and (d) meets the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission promulgated thereunder and by any National Securities Exchange on which the Common Units are listed or admitted to trading.

“Ineligible Holder” has the meaning assigned such term in Section 4.9(c).

“Initial Limited Partners” means AIM Midstream, the LTIP Partners and the General Partner (with respect to the Common Units, Subordinated Units and Incentive Distribution Rights held by them).

“Initial Public Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

“Initial Unit Price” means (a) with respect to the Common Units and the Subordinated Units, the IPO Price or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially issued by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

“Interest Rate Hedge Contract” means any interest rate exchange, swap, forward, cap, floor collar or other similar agreement or arrangement entered into for the purpose of reducing the exposure of the Partnership Group to fluctuations in interest rates in their financing activities and not for speculative purposes.

“Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account or for a deferred purchase price in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member; (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal asset retirements or replacements; (d) the termination of Commodity Hedge Contracts or Interest Rate Hedge Contracts prior to the respective specified termination dates; (e) capital contributions received by a Group Member or, in the case of capital contributions received by a Person that is not a Subsidiary of the Partnership, capital contributions received from the owner(s) or members of such Person that is not a Group Member; or (f) corporate reorganizations or restructurings.

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“Investment Capital Expenditures” means capital expenditures other than Maintenance Capital Expenditures and Expansion Capital Expenditures. Investment Capital Expenditures will include cash contributed by a Group Member to an entity of which such Group Member is, or after such contribution will be directly or indirectly, an equity owner to be used by such entity for capital expenditures other than Maintenance Capital Expenditures and Expansion Capital Expenditures.

“IPO Closing Date” means the closing date of the sale of the Common Units in the Initial Public Offering.

“IPO Common Units” means the Common Units sold in the Initial Public Offering.

“IPO Price” means the price per Common Unit at which the Underwriters offer the Common Units for sale to the public as set forth on the cover page of the final prospectus filed pursuant to Rule 424(b) of the rules and regulations of the Commission with respect to the Initial Public Offering.

“IPO Proceeds” means the portion of the net proceeds received by the Partnership from the issuance and sale of Common Units in connection with the closing of the Initial Public Offering that, according to the disclosure set forth in the section of the Registration Statement entitled “Use of Proceeds,” are to be distributed to AIM Midstream, the LTIP Partners and the General Partner.

“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

“Limited Partner” means, unless the context otherwise requires, each Initial Limited Partner, each Additional Limited Partner and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as a limited partner of the Partnership; provided, however, that when the term “Limited Partner” is used herein in the context of any vote or other approval, including Article XIII and Article XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may be required by law.

“Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Incentive Distribution Rights or other Partnership Interests or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement; provided, however, that when the term “Limited Partner Interest” is used herein in the context of any vote or other approval, including Article XIII and Article XIV, such term shall not, solely for such purpose, include any Incentive Distribution Right except as may be required by law.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“Long Term Incentive Plan” means the Long-Term Incentive Plan of the General Partner, as may be amended, or any equity compensation plan successor thereto or otherwise adopted by the General Partner or the Partnership.

“LTIP Partners” means those Limited Partners holding on the date hereof Common Units issued pursuant to the Long Term Incentive Plan, in respect of such Common Units.

“Maintenance Capital Expenditures” means cash expenditures (including expenditures (i) for the addition or improvement to or the replacement of the capital assets owned by any Group Member, (ii) for the acquisition of existing, or the construction or development of new, capital assets or (iii) for any integrity management program, including pursuant to the Gas Transmission Pipeline Integrity Management Rule (49 CFR Part 192, Subpart O) and any corresponding rule of state law) if such expenditures are made to

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maintain, including over the long term, the operating capacity or operating income of the Partnership Group. Maintenance Capital Expenditures shall exclude Expansion Capital Expenditures or Investment Capital Expenditures, but include interest (and related fees) on debt incurred and distributions in respect of equity issued, other than equity issued in the Initial Public Offering, in each case, to finance the construction or development of a replacement asset and paid in respect of the period beginning on the date that a Group Member enters into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that such replacement asset Commences Commercial Service and the date that such replacement asset is abandoned or disposed of. Debt incurred to pay or equity issued, other than equity issued in the Initial Public Offering, to fund construction or development period interest payments, or such construction or development period distributions in respect of equity, shall also be deemed to be debt or equity, as the case may be, incurred to finance the construction or development of a replacement asset and the incremental Incentive Distributions paid relating to newly issued equity shall be deemed to be distributions paid on equity issued to finance the construction or development of a replacement asset. Maintenance Capital Expenditures will include cash contributed by any Group Member to an entity of which such Group Member is, or after such contribution will be, directly or indirectly, an equity owner to be used by such entity for capital expenditures of the types described in clauses (i), (ii) or (iii) above.

“Merger Agreement” has the meaning assigned to such term in Section 14.1.

“Minimum Quarterly Distribution” means $0.4125 per Unit per Quarter (such amount having been determined by the Board of Directors at the time of the Initial Public Offering (or with respect to the Quarter that includes the IPO Closing Date, it means the product of such amount multiplied by a fraction, the numerator of which is the number of days in such Quarter after the IPO Closing Date and the denominator of which is the total number of days in such Quarter)), subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act and any successor to such statute.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liability either assumed by the Partnership upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any Liability either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case, as determined and required by Treasury Regulations promulgated under Section 704(b) of the Code.

“Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

“Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

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“Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable period, the sum, if positive, of all items of income, gain, loss or deduction (a) recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or series of related transactions (excluding any disposition to a member of the Partnership Group) or (b) deemed recognized by the Partnership Group pursuant to Section 5.5(d); provided, however that the items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Net Termination Loss” means, for any taxable period, the sum, if negative, of all items of income, gain, loss or deduction (a) recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or series of related transactions (excluding any disposition to a member of the Partnership Group) or (b) deemed recognized by the Partnership Group pursuant to Section 5.5(d); provided, however the items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“New Credit Agreement” means the Credit Agreement, dated as of July , 2011 by and among the Operating Company, as Borrower, the Partnership, as Parent, Bank of America, N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Comerica Bank and Citicorp North America, Inc., as Co-Syndication Agents, BBVA Compass as Documentation Agent, and the other financial institutions party thereto.

“New Credit Facility Proceeds” means the portion of the net proceeds of the Partnership’s borrowings made simultaneously with the closing of the Initial Public Offering under its new credit facility that, according to the disclosure set forth in the section of the Registration Statement entitled “Use of Proceeds,” are to be distributed to AIM Midstream.

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b). If such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b).

“Notional General Partner Unit” means notional units used solely to calculate the General Partner’s Percentage Interest. The General Partner Units (as that term is defined in the First A/R Partnership Agreement) Outstanding (as that term is defined in the First A/R Partnership Agreement) under the First A/R Partnership Agreement immediately prior to effectiveness of this Agreement shall be immediately and automatically converted in the same number of Notional General Partner Units upon effectiveness of this Agreement. Notional General Partner Units shall not constitute “Units” for any purpose of this Agreement. There shall initially be Notional General Partner Units (resulting in the General Partner’s Percentage Interest being 2% after giving effect to any exercise of the Over-Allotment Option). If the General Partner makes additional Capital Contributions pursuant to Section 5.2(b) to maintain its Percentage Interest, the number of Notional General Partner Units shall be increased proportionally to reflect the maintenance of such Percentage Interest.

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“Operating Company” means American Midstream, LLC, a Delaware limited liability company, and any successors thereto.

“Operating Expenditures” means all Partnership Group cash expenditures (or the Partnership’s proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including taxes, reimbursements of expenses of the 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 (effected on or after the IPO Closing Date) of any Interest Rate Hedge Contract or Commodity Hedge Contract prior to the expiration of its stipulated settlement or termination date shall 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, director and officer compensation, repayment of Working Capital Borrowings and non-Pro Rata repurchases of Units (other than those made with the proceeds of an Interim Capital Transaction), subject to the following:

(a) deemed repayments of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of “Operating Surplus” shall not constitute Operating Expenditures when actually repaid;

(b) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures when actually repaid;

(c) Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) Investment Capital Expenditures, (iii) actual Maintenance Capital Expenditures, (iv) payment of transaction expenses (including taxes) relating to Interim Capital Transactions, (v) distributions to Partners (including any distributions made pursuant to Section 6.4(a)), (vi) non-Pro Rata purchases of the Units of any class made with the proceeds of an Interim Capital Transaction or (vii) any other payments made in connection with the Initial Public Offering that are described under “Use of Proceeds” in the Registration Statement; and

(d) where capital expenditures are made in part for Maintenance Capital Expenditures and in part for other purposes, the General Partner, with the concurrence of the Conflicts Committee, shall determine the allocation of such capital expenditures between Maintenance Capital Expenditures and capital expenditures made for other purposes and, with respect to the part of such capital expenditures consisting of Maintenance Capital Expenditures, the period over which Maintenance Capital Expenditures will be deducted as an Operating Expenditure in calculating Operating Surplus.

“Operating Surplus” means, with respect to any period commencing on the IPO Closing Date and ending prior to the Liquidation Date, on a cumulative basis and without duplication,

(a) the sum of:

(i) $11.5 million;

(ii) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) for the period beginning on the IPO Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions (except to the extent specified in Section 6.5 and provided that cash receipts from the termination (effected on or after the IPO Closing Date) of a Commodity Hedge Contract or an Interest Rate Hedge Contract prior to its specified termination date shall be included in Operating Surplus in equal quarterly installments over the remaining scheduled life of such Commodity Hedge Contract or Interest Rate Hedge Contract);

(iii) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings; and

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(iv) 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 the Group Member enters 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 or the date that it is abandoned or disposed of (equity issued to fund construction-, acquisition-, development- or improvement- period interest payments on debt incurred, or construction-, acquisition-, development- or improvement-period distributions on equity issued, to finance the construction, acquisition or development of a Capital Improvement or replacement of a capital asset shall also be deemed to be equity issued to finance the construction, acquisition or development of a Capital Improvement or replacement of a capital asset for purposes of this clause (iv)); less

(b) the sum of:

(i) Operating Expenditures for the period beginning on the IPO Closing Date and ending on the last day of such period;

(ii) the amount of cash reserves (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) established by the General Partner after the IPO Closing Date to provide funds for future Operating Expenditures; and

(iii) all Working Capital Borrowings incurred on or after the IPO Closing Date not repaid within twelve months after having been incurred;

provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing, “Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero. Cash receipts from an Investment Capital Expenditure shall be treated as cash receipts only to the extent they are a return on principal, but in no event shall a return of principal be treated as cash receipts.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of an Over-Allotment Option.

“Outstanding” means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Interests of any class then Outstanding, all Partnership Interests owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Units shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall

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not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Interests issued by the Partnership with the prior approval of the Board of Directors.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means American Midstream Partners, LP, a Delaware limited partnership.

“Partnership Group” means collectively the Partnership and its Subsidiaries.

“Partnership Interest” means any class or series of equity interest in the Partnership, which shall include any General Partner Interest and Limited Partner Interests but shall exclude any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

“Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per-Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

“Percentage Interest” means as of any date of determination (a) as to the General Partner Interest (calculated based upon a number of Notional General Partner Units), and as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of Notional General Partner Units held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of Outstanding Units and Notional General Partner Units, and (b) as to the holders of other Partnership Interests issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.

“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners and/or Record Holders, apportioned among all Partners and/or Record Holders in accordance with their relative Percentage Interests and (c) when used with respect to holders of Incentive Distribution Rights, apportioned among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder.

“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership that includes the IPO Closing Date, the portion of such fiscal quarter after the IPO Closing Date.

“Rate Eligibility Trigger” has the meaning assigned to such term in Section 4.9(a)(i).

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“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means (a) with respect to Partnership Interests of any class of Partnership Interests for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the closing of business on a particular Business Day, or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the closing of business on such Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

“Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-173191) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of Common Units in the Initial Public Offering.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units or Subordinated Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the General Partner (as holder of the Notional General Partner Units), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the Notional General Partner Units for each prior taxable period, and (iii) with respect to the holders of Incentive Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

“Required Allocations” means any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vi), Section 6.1(d)(vii) or Section 6.1(d)(ix).

“Reset MQD” has the meaning assigned to such term in Section 5.11(e).

“Reset Notice” has the meaning assigned to such term in Section 5.11(b).

“Retained Converted Subordinated Unit” has the meaning assigned to such term in Section 5.5(c)(ii).

“Second Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(E).

“Second Target Distribution” means 125% of the Minimum Quarterly Distribution (or, with respect to the Quarter which includes the IPO Closing Date, it means the product of 125% of the Minimum Quarterly Distribution multiplied by a fraction of which the numerator is equal to the number of days in such Quarter after the IPO Closing Date and of which the denominator is the total number of days in such Quarter), subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

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“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the Notional General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

“Special Approval” means approval by a majority of the members of the Conflicts Committee.

“Subordinated Unit” means a Partnership Interest representing a fractional part of the Partnership Interests of all Limited Partners and having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term “Subordinated Unit” does not include a Common Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.

“Subordination Period” means the period commencing immediately following the distributions provided for in Section 6.4(a) on the IPO Closing Date and ending on the first to occur of the following dates:

(a) the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending September 30, 2014 in respect of which:

(i) (A) distributions of Available Cash from Operating Surplus (excluding the distributions provided for in Section 6.4(a)) on each of (I) the Outstanding Common Units, Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and (II) the General Partner Interest, in each case with respect to each of the three consecutive non-overlapping four-Quarter periods immediately preceding such date, equaled or exceeded the sum of the Minimum Quarterly Distribution for each such four-Quarter period on all Common Units, Subordinated Units, any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding at the time such distributions were paid, and the related distributions on the General Partner Interest; and

(B) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of (I) the Minimum Quarterly Distribution for each such four-Quarter period on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding during such periods on a Fully Diluted Weighted Average Basis, and (II) the related distributions on the General Partner Interest (for the avoidance of doubt, not including the distribution to the General Partner provided for in Section 6.4(a)); and

(ii) there are no Cumulative Common Unit Arrearages;

(b) the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter (beginning with the Quarter ending September 30, 2012) in respect of which:

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immediately preceding such date equaled or exceeded 150% of the Minimum Quarterly Distribution for such four-Quarter period on all of (I) the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding at the time such distributions were paid, and (II) the related distributions on the General Partner Interest, in each case in respect of such period; and

(B) the Adjusted Operating Surplus for the four-Quarter period immediately preceding such date equaled or exceeded the sum of (I) 150% of the Minimum Quarterly Distribution for such four-Quarter period on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, in each case that were Outstanding during such period on a Fully Diluted Weighted Average Basis, and (II) the related distributions on the General Partner Interest and the corresponding Incentive Distributions (for the avoidance of doubt, not including the distribution to the General Partner provided for in Section 6.4(a));

(ii) distributions of Available Cash from Operating Surplus (excluding the distributions provided for in Section 6.4(a)) on each of (A) the Outstanding Common Units, Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units that equaled or exceeded the Minimum Quarterly Distribution, and (B) the General Partner Interest were made, in each case with respect to each Quarter during the four-Quarter period immediately preceding such date; and

(iii) there are no Cumulative Common Unit Arrearages; and

(c) the date on which the General Partner is removed as general partner of the Partnership upon the requisite vote by holders of Outstanding Units under circumstances where Cause does not exist and no Units held by the General Partner and its Affiliates are voted in favor of such removal;

provided, however, that, for purposes of determining whether the test in clause (a)(i)(B) above has been satisfied, Adjusted Operating Surplus will be adjusted upwards or downwards if the Conflicts Committee determines in good faith that the amount of Estimated Maintenance Capital Expenditures used in the determination of Adjusted Operating Surplus in such clause was materially incorrect, based on circumstances prevailing at the time of original determination of Estimated Maintenance Capital Expenditures, for any one or more of the preceding two four-Quarter periods.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b).

“Target Distributions” means each of the Minimum Quarterly Distribution, the First Target Distribution, Second Target Distribution and Third Target Distribution.

“Third Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(F).

“Third Target Distribution” means 150% of the Minimum Quarterly Distribution (or, with respect to the Quarter which includes the IPO Closing Date, it means the product of 150% of the Minimum Quarterly Distribution multiplied by a fraction of which the numerator is equal to the number of days in such Quarter

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after the IPO Closing Date and of which the denominator is the total number of days in such Quarter), subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

“Trading Day” means, for the purpose of determining the Current Market Price of any class of Limited Partner Interests, a day on which the principal National Securities Exchange on which such class of Limited Partner Interests are listed is open for the transaction of business or, if Limited Partner Interests of a class are not listed on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

“transfer” has the meaning assigned to such term in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the General Partner to act as registrar and transfer agent for the Common Units; provided, that if no Transfer Agent is specifically designated for any other Partnership Interests, the General Partner shall act in such capacity.

“Underwriters” means the underwriters in the Initial Public Offering.

“Underwriting Agreement” means the underwriting agreement among the Underwriters, the Partnership, the General Partner and the other parties thereto, providing for the purchase of Common Units by the Underwriters in connection with the Initial Public Offering.

“Unit” means a Partnership Interest that is designated as a “Unit” and shall include Common Units and Subordinated Units but shall not include (i) Notional General Partner Units (or the General Partner Interest represented thereby) or (ii) Incentive Distribution Rights.

“Unitholders” means the holders of Units.

“Unit Majority” means (i) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a separate class, and at least a majority of the Outstanding Subordinated Units, voting as a separate class; and (ii) after the end of the Subordination Period, at least a majority of the Outstanding Common Units, voting as a single class.

“Unpaid MQD” has the meaning assigned to such term in Section 6.1(c)(i)(B).

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d))) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

“Unrecovered Initial Unit Price” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an IPO Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an IPO Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

“Unrestricted Person” means (a) each Indemnitee, (b) each Partner, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, a General Partner or any Departing General Partner or any Affiliate of any Group Member, a General Partner or any Departing General Partner and (d) any Person the General Partner designates as an Unrestricted Person for purposes of this Agreement.

“U.S. GAAP” means United States generally accepted accounting principles consistently applied.

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“Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).

“Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Partners made pursuant to a credit facility, commercial paper facility or other similar financing arrangements, provided that when such borrowings are incurred it is the intent of the borrower to repay such borrowings within 12 months other than from additional Working Capital Borrowings.

Section 1.2 Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” or words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” or “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

ARTICLE II

ORGANIZATION

Section 2.1 Formation.

The General Partner and AIM Midstream have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act. The General Partner hereby amends and restates the First Amended Agreement of Limited Partnership of American Midstream Partners, LP in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2 Name.

The name of the Partnership shall be “American Midstream Partners, LP” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “LP,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices.

Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, New Castle County, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Partnership shall be located at 1614 15th Street, Suite 300, Denver, CO 80202, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner shall determine necessary or appropriate. The address of the General Partner shall be 1614 15th Street, Suite 300, Denver, CO 80202, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

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Section 2.4 Purpose and Business.

The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

Section 2.5 Powers.

The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Term.

The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7 Title to Partnership Assets.

Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to any successor General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

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ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability.

The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business.

No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. All actions taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participating in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners.

Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, each Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners.

(a) In addition to other rights provided by this Agreement or by applicable law (other than Section 17-305(a) of the Delaware Act, the obligations of which are expressly replaced in their entirety by the provisions below and Section 8.3), and except as limited by Section 3.4(a)(i), each Limited Partner shall have the right, for a purpose that is reasonably related, as determined by the General Partner, to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand and at such Limited Partner’s own expense to obtain:

(i) true and full information regarding the status of the business and financial condition of the Partnership (provided that the requirements of this Section 3.4(a)(i) shall be satisfied to the extent the Limited Partner is furnished the Partnership’s most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the Commission pursuant to Section 13 of the Exchange Act);

(ii) a current list of the name and last known business, residence or mailing address of each Record Holder;

(iii) a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed; and

(iv) such other information regarding the affairs of the Partnership as the General Partner determines is just and reasonable.

(b) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith

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believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF

PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates.

Notwithstanding anything otherwise to the contrary herein, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by certificates. Certificates that may be issued shall be executed on behalf of the Partnership by the Chairman of the Board, President or any Executive Vice President or Vice President and the Chief Financial Officer or the Secretary or any Assistant Secretary of the General Partner. No Certificate for a class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent for such class of Partnership Interests; provided, however, that if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c), if Common Units are evidenced by Certificates, on or after the date on which Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7, the Record Holders of such Subordinated Units (i) if the Subordinated Units are evidenced by Certificates, may exchange such Certificates for Certificates evidencing Common Units or (ii) if the Subordinated Units are not evidenced by Certificates, shall be issued Certificates evidencing Common Units.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent (for Common Units) or the General Partner (for Partnership Interests other than Common Units), the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent (for Common Units) or the General Partner (for Partnership Interests other than Common Units) shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent (for Common Units) shall countersign, a new Certificate in place of any Certificate previously issued, or issue uncertificated Common Units, if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate or the issuance of uncertificated Units before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests

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represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate or uncertificated Units.

(c) As a condition to the issuance of any new Certificate or uncertificated Units under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders.

The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Partnership Interest and (b) bound by this Agreement and shall have the rights and obligations of a Partner, as the case may be, hereunder as, and to the extent, provided herein.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall mean a transaction (i) by which the General Partner assigns its General Partner Interest to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, excluding a pledge, encumbrance, hypothecation or mortgage but including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be, to the fullest extent permitted by law, null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of any Partner of any or all of the shares of stock, membership or limited liability company interests, partnership interests or other ownership interests in such Partner, and the term “transfer” shall not mean any such disposition.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests.

(b) The Partnership shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions hereof, the appropriate officers of the General Partner on behalf of the Partnership shall

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execute and deliver, and in the case of Certificates evidencing Limited Partner Interests, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(c) By acceptance of the transfer of any Limited Partner Interests in accordance with this Section 4.5 and except as provided in Section 4.9, each transferee of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement and (iv) makes the consents, acknowledgements and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests shall be freely transferable.

(e) The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units, Common Units and Incentive Distribution Rights to one or more Persons.

Section 4.6 Transfer of the General Partner’s General Partner Interest.

(a) Subject to Section 4.6(c) below, prior to June 30, 2021, the General Partner shall not transfer all or any part of its General Partner Interest (represented by Notional General Partner Units) to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

(b) Subject to Section 4.6(c) below, on or after June 30, 2021, the General Partner may transfer all or any of its General Partner Interest without Unitholder approval.

(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or limited liability company membership interest held by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

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Section 4.7 Transfer of Incentive Distribution Rights.

The General Partner or any other holder of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without Unitholder approval.

Section 4.8 Restrictions on Transfers.

(a) Notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (ii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it determines, with the advice of counsel, that such restrictions are necessary or advisable to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for U.S. federal income tax purposes or (ii) preserve the uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) The transfer of a Common Unit that has been issued upon conversion of a Subordinated Unit shall be subject to the restrictions imposed by Section 6.7(c).

(d) The transfer of Common Units that have been issued upon conversion of Incentive Distribution Rights shall be subject to the restrictions imposed by Section 6.8(b).

(e) Nothing contained in this Agreement, other than Section 4.8(a), shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

Section 4.9 Eligibility Certifications; Ineligible Holders.

(a) If at any time the General Partner determines, with the advice of counsel, that

(i) the U.S. federal income tax status (or lack of proof of the U.S. federal income tax status) of one or more Limited Partners has or is reasonably likely to have a material adverse effect on the rates that can be charged to customers by any Group Member on assets that are subject to regulation by the FERC or analogous regulatory body (a “Rate Eligibility Trigger”); or

(ii) any Group Member is subject to any federal, state or local law or regulation that would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Partner (a “Citizenship Eligibility Trigger”);

then, the General Partner may adopt such amendments to this Agreement as it determines to be necessary or advisable to (x) in the case of a Rate Eligibility Trigger, obtain such proof of the U.S. federal income tax status of the Limited Partners and, to the extent relevant, their beneficial owners, as the General Partner determines to be necessary to establish those Limited Partners whose U.S. federal income tax status does not or would not have a material adverse effect on the rates that can be charged to customers by any Group Member or (y) in the case of a Citizenship Eligibility Trigger, obtain such proof of the nationality, citizenship or other related status of the Partner (or, if the Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner determines to be necessary to establish those Partners whose status as Partners does not or would not subject any Group Member to a significant risk of cancellation or forfeiture of any of its properties or interests therein.

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(b) Such amendments may include provisions requiring all Partners to certify as to their (and their beneficial owners’) status as Eligible Holders upon demand and on a regular basis, as determined by the General Partner, and may require transferees of Units to so certify prior to being admitted to the Partnership as a Partner (any such required certificate, an “Eligibility Certificate”).

(c) Such amendments may provide that any Partner who fails to furnish to the General Partner within a reasonable period requested proof of its (and its beneficial owners’) status as an Eligible Holder or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Partner is not an Eligible Holder (such a Partner an “Ineligible Holder”) the Partnership Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10. In addition, the General Partner shall be substituted for all Limited Partners that are Ineligible Holders as the Limited Partner in respect of the Ineligible Holders’ Partnership Interests.

(d) The General Partner shall, in exercising voting rights in respect of Partnership Interests held by it on behalf of Ineligible Holders, distribute the votes in the same ratios as the votes of Partners (including the General Partner and its Affiliates) in respect of Partnership Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.

(e) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Holder of his Partnership Interest (representing his right to receive his share of such distribution in kind).

(f) At any time after an Ineligible Holder can and does certify that he has become an Eligible Holder, an Ineligible Holder may, upon application to the General Partner, request that with respect to any Partnership Interests of such Ineligible Holder not redeemed pursuant to Section 4.10, such Ineligible Holder be admitted as a Limited Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as a Limited Partner and shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the Limited Partner in respect of such Ineligible Holder’s Partnership Interests.

Section 4.10 Redemption of Partnership Interests of Ineligible Holders.

(a) If at any time a Partner fails to furnish an Eligibility Certificate or other information requested within the period of time specified in amendments adopted pursuant to Section 4.9, or if upon receipt of such Eligibility Certificate or other information the General Partner determines, with the advice of counsel, that a Partner is not an Eligible Holder, the Partnership may, unless the Partner establishes to the satisfaction of the General Partner that such Partner is an Eligible Holder or has transferred his Partnership Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certificate to the General Partner prior to the date fixed for redemption as provided below, redeem the Partnership Interest of such Partner as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Partner, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificates evidencing the Redeemable Interests) and that on and after the date fixed for redemption no further allocations or distributions to which the Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Partnership Interests of the class to be so redeemed multiplied by the number of Partnership Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as

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determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) The Partner or his duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Partner at the place specified in the notice of redemption, of the Certificates evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Partnership Interests.

(b) The provisions of this Section 4.10 shall also be applicable to Partnership Interests held by a Partner as nominee of a Person determined to be an Ineligible Holder.

(c) Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Partnership Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Partnership Interest certifies to the satisfaction of the General Partner that he is an Eligible Holder. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND

ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Intentionally Omitted.

Section 5.2 Contributions by the General Partner and the Initial Limited Partners.

(a) Prior to the IPO Closing Date, the General Partner, AIM Midstream and the LTIP Partners made capital contributions in exchange for Partnership Interests.

(b) Upon the issuance of any Additional Limited Partner Interests by the Partnership (other than (i) the Common Units issued in the Initial Public Offering (including Common Units issued upon the exercise by the Underwriters of the Over-Allotment Option), (ii) any Common Units issued upon conversion of Subordinated Units and (iii) Common Units issued pursuant to Section 5.11), the General Partner may, in order to maintain its Percentage Interest, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest immediately prior to the issuance of such Additional Limited Partner Interests by the Partnership by (B) 100 less the General Partner’s Percentage Interest immediately prior to the issuance of such Additional Limited Partner Interests by the Partnership times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such Additional Limited Partner Interests. Except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.3 Contributions by Limited Partners.

(a) On the IPO Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, as set forth in the Underwriting Agreement.

(b) Upon the exercise, if any, of the Over-Allotment Option, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

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Section 5.4 Interest and Withdrawal of Capital Contributions.

No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon liquidation of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.5 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction that is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement) of all property owned by (x) any other Group Member that is classified as a partnership for U.S. federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for U.S. federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code that may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

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(iv) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined under the rules prescribed by Treasury Regulation Section 1.704-3(d)(2), as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

(vi) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).

(c) (i) A transferee of a Partnership Interest shall succeed to a Pro Rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(ii) Subject to Section 6.7(c), immediately prior to the transfer of a Subordinated Unit or of a Common Unit that has been issued upon conversion of a Subordinated Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this Section 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or Common Units issued upon conversion of Subordinated Units will (A) first, be allocated to the Subordinated Units or Common Units issued upon conversion of Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or Common Units issued upon conversion of Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Subordinated Units or Common Units issued upon conversion of Subordinated Units (“Retained Converted Subordinated Units”). Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Subordinated Units or Retained Converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee’s Capital Account established with respect to the transferred Subordinated Units or Common Units issued upon conversion of Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove.

(iii) Upon the issuance of IDR Reset Common Units pursuant to Section 5.11(a), the Capital Account maintained with respect to the Incentive Distribution Rights shall (A) first, be allocated to IDR Reset Common Units in an amount equal to the product of (x) the Aggregate Quantity of IDR Reset Common Units and (y) the Per Unit Capital Amount for an IPO Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the holder of the Incentive Distributions Rights. In the event that there is not a sufficient Capital Account associated with the Incentive Distribution Rights to allocate the full Per Unit Capital Amount for an IPO Common Unit to the IDR Reset Common Units in accordance with clause (A) of this Section 5.5(c)(iii), the IDR Reset Common Units shall be subject to Section 6.1(d)(x)(B) and Section 6.1(d)(x)(C).

(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Account of each Partner and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance for an amount equal to its fair market value and had been allocated to the Partners at such time pursuant to Section 6.1(c)

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and Section 6.1(d) in the same manner as any item of gain or loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated; provided, however, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1(c) and Section 6.1(d) in the same manner as any item of gain or loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.6 Issuances of Additional Partnership Interests.

(a) The Partnership may issue additional Partnership Interests and options, rights, warrants, appreciation rights, tracking and phantom interests, and other economic interests relating to the Partnership Interests (including pursuant to Section 7.4(c)) for any partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Interest or other security authorized to be issued by the Partnership pursuant to Section 5.6(a) or Section 7.4(c) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Interests or other securities), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Interest (including sinking fund provisions) or other security; (v) whether such Partnership Interest or other security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest or other security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and options, rights, warrants, appreciation rights, tracking and phantom interests, and other economic interests in the Partnership or relating to Partnership Interests pursuant to this Section 5.6 or Section 7.4(c), (ii) the conversion of the Combined Interest into Units

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pursuant to the terms of this Agreement, (iii) the issuance of Common Units pursuant to Section 5.11, (iv) the admission of Additional Limited Partners and (v) all additional issuances of Partnership Interests. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests or other securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or other securities or in connection with the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

Section 5.7 Conversion of Subordinated Units.

(a) All of the Subordinated Units shall automatically convert into Common Units on a one-for-one basis on the expiration or termination of the Subordination Period.

(b) A Common Unit that has been issued upon conversion of a Subordinated Unit shall be subject to the provisions of Section 6.7.

Section 5.8 Limited Preemptive Right.

Except as provided in this Section 5.8 and in Section 5.2 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest or other security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, that it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Interests. Any determination by the General Partner whether to exercise its right pursuant to the immediately preceding sentence shall be a determination made in its individual capacity and not as the general partner of the Partnership, and such determination may be made in accordance with Section 7.9(c).

Section 5.9 Splits and Combinations.

(a) Subject to Section 5.9(d), Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per-Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units (including the number of Subordinated Units that may convert prior to the end of the Subordination Period) are proportionately adjusted.

(b) Whenever such a Pro Rata distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) If a Pro Rata distribution of Partnership Interests, or a subdivision or combination of Partnership Interests, is made as contemplated in this Section 5.9, the number of Notional General Partner Units constituting the Percentage Interest of the General Partner (as determined immediately prior to the Record

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Date for such distribution, subdivision or combination), shall be appropriately adjusted as of the effective date for payment of such distribution, subdivision or combination to maintain such Percentage Interest of the General Partner.

(d) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates or uncertificated Partnership Interests to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate or uncertificated Partnership Interests, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(e) The Partnership shall not issue fractional Units or Notional General Partner Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units or fractional Notional General Partner Units but for the provisions of this Section 5.9(e), each fractional Unit or fractional Notional General Partner Unit shall be rounded to the nearest whole Unit or Notional General Partner Unit (and a 0.5 Unit or Notional General Partner Unit shall be rounded to the next higher Unit or Notional General Partner Unit).

Section 5.10 Fully Paid and Non-Assessable Nature of Limited Partner Interests.

All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by either or both of Sections 17-607 and 17-804 of the Delaware Act.

Section 5.11 Issuance of Common Units in Connection with Reset of Incentive Distribution Rights.

(a) Subject to the provisions of this Section 5.11, the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right, exercisable at its option at any time when there are no Subordinated Units Outstanding and the Partnership has made a distribution pursuant to Section 6.4(c)(v) for each of the four most recently completed Quarters and the amount of each such distribution did not exceed Adjusted Operating Surplus for such Quarter, to make an election (the “IDR Reset Election”) to cause the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive their respective proportionate share of a number of Common Units (the “IDR Reset Common Units”) derived by dividing (i) the average aggregate amount of cash distributions made by the Partnership for the two full Quarters immediately preceding the giving of the Reset Notice (as defined in Section 5.11(b)) in respect of the Incentive Distribution Rights by (ii) the average of the cash distributions made by the Partnership in respect of each Common Unit for the two full Quarters immediately preceding the giving of the Reset Notice (the number of Common Units determined by such quotient is referred to herein as the “Aggregate Quantity of IDR Reset Common Units”). If at the time of any IDR Reset Election the General Partner and its Affiliates are not the holders of a majority interest of the Incentive Distribution Rights, then the IDR Reset Election shall be subject to the prior written concurrence of the General Partner that the conditions described in the immediately preceding sentence have been satisfied. The Percentage Interest of the General Partner, with respect to the General Partner Interest, after the issuance of the Aggregate Quantity of IDR Reset Common Units shall equal the Percentage Interest of the General Partner, with respect to the General Partner Interest, prior to the issuance of the Aggregate Quantity of IDR Reset Common Units and the General Partner shall not be obligated to make any additional Capital Contribution to the Partnership in order to maintain its Percentage Interest in connection therewith and shall be issued an additional number of Notional General Partner Units as is required to maintain such Percentage Interest. The making of the IDR Reset Election in the manner specified in Section 5.11(b) shall cause each of the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive IDR Reset Common Units on the basis specified above, without any

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further approval required by the General Partner or the Unitholders, at the time specified in Section 5.11(c) unless the IDR Reset Election is rescinded pursuant to Section 5.11(d).

(b) To exercise the right specified in Section 5.11(a), the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall deliver a written notice (the “Reset Notice”) to the Partnership. Within 10 Business Days after the receipt by the Partnership of such Reset Notice, the Partnership shall deliver a written notice to the holder or holders of the Incentive Distribution Rights of the Partnership’s determination of the aggregate number of IDR Reset Common Units that each holder of Incentive Distribution Rights will be entitled to receive.

(c) The holder or holders of the Incentive Distribution Rights will be entitled to receive the Aggregate Quantity of IDR Reset Common Units on the fifteenth Business Day after receipt by the Partnership of the Reset Notice; provided, however, that the issuance of IDR Reset Common Units to the holder or holders of the Incentive Distribution Rights shall not occur prior to the approval of the listing or admission for trading of such IDR Reset Common Units by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.

(d) If the principal National Securities Exchange upon which the Common Units are then traded has not approved the listing or admission for trading of the Common Units to be issued pursuant to this Section 5.11 on or before the 30th calendar day following the Partnership’s receipt of the Reset Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right to either rescind the IDR Reset Election or elect to receive other Partnership Interests having such terms as the General Partner may approve, with the approval of a Conflicts Committee, that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of IDR Reset Common Units would have had at the time of the Partnership’s receipt of the Reset Notice, as determined by the General Partner, and (ii) for the subsequent conversion (on terms acceptable to the National Securities Exchange upon which the Common Units are then traded) of such Partnership Interests into Common Units within not more than 12 months following the Partnership’s receipt of the Reset Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights).

(e) The Target Distributions shall be adjusted at the time of the issuance of Common Units or other Partnership Interests pursuant to this Section 5.11 such that (i) the Minimum Quarterly Distribution shall be reset to equal the average cash distribution amount per Common Unit for the two Quarters immediately prior to the Partnership’s receipt of the Reset Notice (the “Reset MQD”), (ii) the First Target Distribution shall be reset to equal 115% of the Reset MQD, (iii) the Second Target Distribution shall be reset to equal 125% of the Reset MQD and (iv) the Third Target Distribution shall be reset to equal 150% of the Reset MQD.

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ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes.

For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.5(b)) for each taxable period shall be allocated among the Partners as provided herein below.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable period shall be allocated as follows:

(i) First, to the General Partner until the aggregate of the Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) and the Net Termination Gain allocated to the General Partner pursuant to Section 6.1(c)(i)(A) or Section 6.1(c)(iv)(A) for the current and all previous taxable periods is equal to the aggregate of the Net Loss allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods and the Net Termination Loss allocated to the General Partner pursuant to Section 6.1(c)(ii)(D) or Section 6.1(c)(iii)(B) for the current and all previous taxable periods; and

(ii) The balance, if any, (x) to the General Partner in accordance with its Percentage Interest, and (y) to all Unitholders, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x).

(b) Net Loss. After giving effect to the special allocations set forth in Section 6.1(d), Net Loss for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Loss for such taxable period shall be allocated as follows:

(i) First, to the General Partner and the Unitholders, Pro Rata; provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account); and

(ii) The balance, if any, 100% to the General Partner.

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Termination Gain or Net Termination Loss (including a pro rata part of each item of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss) for such taxable period shall be allocated in the manner set forth in this Section 6.1(c). All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 and Section 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(i) Except as provided in Section 6.1(c)(iv), Net Termination Gain (including a pro rata part of each item of income, gain, loss, and deduction taken into account in computing Net Termination Gain) shall be allocated:

(A) First, to the General Partner until the aggregate of the Net Termination Gain allocated to the General Partner pursuant to this Section 6.1(c)(i)(A) or Section 6.1(c)(iv)(A) and the Net Income allocated to the General Partner pursuant to Section 6.1(a)(i) for the current and all previous taxable periods is equal to the aggregate of the Net Loss allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods and the Net Termination Loss allocated to the General Partner pursuant to Section 6.1(c)(ii)(D) or Section 6.1(c)(iii)(B) for all previous taxable periods;

(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s

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Percentage Interest, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(b)(i) or Section 6.4(c)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid MQD”) and (3) any then existing Cumulative Common Unit Arrearage;

(C) Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable period (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(b)(iii) with respect to such Subordinated Unit for such Quarter;

(D) Fourth, to the General Partner and all Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(b)(iv) and Section 6.4(c)(ii) (the sum of (1), (2), (3) and (4) is hereinafter defined as the “First Liquidation Target Amount”);

(E) Fifth, (x) to the General Partner in accordance with its Percentage Interest, (y) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (E), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(b)(v) and Section 6.4(c)(iii) (the sum of (1) and (2) is hereinafter defined as the “Second Liquidation Target Amount”);

(F) Sixth, (x) to the General Partner in accordance with its Percentage Interest, (y) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (F), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the Second Liquidation Target Amount, and (2) the excess of (aa) the Third Target Distribution less the Second Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(b)(vi) and Section 6.4(c)(iv) (the sum of (1) and (2) is hereinafter defined as the “Third Liquidation Target Amount”); and

(G) Finally, (x) to the General Partner in accordance with its Percentage Interest, (y) 48% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (G).

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(ii) Except as otherwise provided by Section 6.1(c)(iii), Net Termination Loss (including a pro rata part of each item of income, gain, loss, and deduction taken into account in computing Net Termination Loss) shall be allocated:

(A) First, if Subordinated Units remain Outstanding, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Common Unit then Outstanding has been reduced to zero;

(C) Third, to the General Partner and the Unitholders, Pro Rata; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(ii)(C) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account (or increase any existing deficit in its Adjusted Capital Account); and

(D) Fourth, the balance, if any, 100% to the General Partner.

(iii) Any Net Termination Loss deemed recognized pursuant to Section 5.5(d) prior to the Liquidation Date shall be allocated:

(A) First, to the General Partner and the Unitholders, Pro Rata; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(iii)(A) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit in its Adjusted Capital Account); and

(B) The balance, if any, to the General Partner.

(iv) If a Net Termination Loss has been allocated pursuant to Section 6.1(c)(iii), subsequent Net Termination Gain deemed recognized pursuant to Section 5.5(d) prior to the Liquidation Date shall be allocated:

(A) First, to the General Partner until the aggregate Net Termination Gain allocated to the General Partner pursuant to this Section 6.1(c)(iv)(A) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(B);

(B) Second, to the General Partner and the Unitholders, Pro Rata, until the aggregate Net Termination Gain allocated pursuant to this Section 6.1(c)(iv)(B) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(A); and

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

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(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations.

(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) with respect to a Unit exceeds the amount of cash or the Net Agreed Value of property distributed with respect to another Unit (the amount of the excess, an “Excess Distribution” and the Unit with respect to which the greater distribution is paid, an “Excess Distribution Unit”), then (1) there shall be allocated gross income and gain to each Unitholder receiving an Excess Distribution with respect to the Excess Distribution Unit until the aggregate amount of such items allocated with respect to such Excess Distribution Unit pursuant to this Section 6.1(d)(iii)(A) for the current taxable period and all previous taxable periods is equal to the amount of the Excess Distribution; and (2) the General Partner shall be allocated gross income and gain with respect to each such Excess Distribution in an amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time when the Excess Distribution occurs by (y) a percentage equal to 100% less the General Partner’s Percentage Interest at the time when the Excess Distribution occurs, times (bb) the total amount allocated in clause (1) above with respect to such Excess Distribution.

(B) After the application of Section 6.1(d)(iii)(A), the remaining items of Partnership income or gain for the taxable period, if any, shall be allocated (1) to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable period and all previous taxable periods is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the IPO Closing Date to a date 45 days after the end of the current taxable period; and (2) to the General Partner an amount equal to the product of (aa) an amount equal to the quotient determined by dividing (x) the General Partner’s Percentage Interest by (y) the sum of 100 less the General Partner’s Percentage Interest times (bb) the sum of the amounts allocated in clause (1) above.

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(iv) were not in this Agreement.

(v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to

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restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(d)(iv) and this Section 6.1(d)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners Pro Rata. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners Pro Rata.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Economic Uniformity; Changes in Law.

(A) At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership gross income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period (“Final Subordinated Units”) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount that after taking into account the other allocations of income, gain, loss and deduction to be made with respect to such taxable period will equal the product of (A) the number of Final Subordinated Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.

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(B) With respect to an event triggering an adjustment to the Carrying Value of Partnership property pursuant to Section 5.5(d) during any taxable period of the Partnership ending upon, or after, the issuance of IDR Reset Common Units pursuant to Section 5.11, after the application of Section 6.1(d)(x)(A), any Unrealized Gains and Unrealized Losses shall be allocated among the Partners in a manner that to the nearest extent possible results in the Capital Accounts maintained with respect to such IDR Reset Common Units issued pursuant to Section 5.11 equaling the product of (a) the Aggregate Quantity of IDR Reset Common Units and (B) the Per Unit Capital Amount for an IPO Common Unit.

(C) With respect to any taxable period during which an IDR Reset Common Unit is transferred to any Person who is not an Affiliate of the transferor, all or a portion of the remaining items of Partnership gross income or gain for such taxable period shall be allocated 100% to the transferor Partner of such transferred IDR Reset Common Unit until such transferor Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such transferred IDR Reset Common Unit to an amount equal to the Per Unit Capital Account for an IPO Common Unit.

(D) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(d)(x)(D) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. In exercising its discretion under this Section 6.1(d)(xi)(A), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that

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might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii) Corrective and other Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) Except as provided in Section 6.1(d)(xii)(B), in the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d)), the General Partner shall allocate such Additional Book Basis Derivative Items (1) to the holders of Incentive Distribution Rights and the General Partner to the same extent that the Unrealized Gain or Unrealized Loss giving rise to such Additional Book Basis Derivative Items was allocated to them pursuant to Section 5.5(d) and (2) to all Unitholders, Pro Rata, to the extent that the Unrealized Gain or Unrealized Loss giving rise to such Additional Book Basis Derivative Items was allocated to any Unitholders pursuant to Section 5.5(d).

(B) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) or an allocation of Net Termination Gain or Net Termination Loss pursuant to Section 6.1(c) as a result of a sale or other taxable disposition of any Partnership asset that is an Adjusted Property (“Disposed of Adjusted Property”), the General Partner shall allocate (1) additional items of gross income and gain (aa) away from the holders of Incentive Distribution Rights and (bb) to the Unitholders, or (2) additional items of deduction and loss (aa) away from the Unitholders and (bb) to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. Any allocation made pursuant to this Section 6.1(d)(xii)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

(C) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balances of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

(D) For purposes of this Section 6.1(d)(xii), the Unitholders shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders under this Agreement. Without limiting the foregoing, if an Adjusted Property is contributed by the Partnership to another entity classified as a partnership for federal income tax purposes (the “lower tier partnership”), the General Partner may make allocations similar to those described in Sections 6.1(d)(xii)(A)-(C) to the extent the General Partner determines such allocations are necessary to account for the Partnership’s allocable share of income, gain, loss and deduction of the lower tier partnership that relate to the contributed Adjusted Property in a manner that is consistent with the purpose of this Section 6.1(d)(xii).

(xiii) Special Curative Allocation in Event of Liquidation Prior to End of Subordination Period. Notwithstanding any other provision of this Section 6.1 (other than the Required Allocations), if the Liquidation Date occurs prior to the conversion of the last Outstanding Subordinated Unit, then items of income, gain, loss and deduction for the taxable period that includes the Liquidation Date (and, if necessary, items arising in previous taxable periods to the extent the General Partner determines such items may be so allocated), shall be specially allocated among the Partners in the manner determined appropriate by the General Partner so as to cause, to the maximum extent possible, the Capital Account in respect of each Common Unit to equal the amount such Capital Account would have been if all prior allocations of Net

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Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable.

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined appropriate by the General Partner (taking into account the General Partner’s discretion under Section 6.1(d)(x)(D)); provided, that the General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) in all events.

(c) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(d) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(e) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(f) Each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, however, such items for the period beginning on the IPO Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the month in which such gain or loss is

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recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(g) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Except as described in Section 6.3(b) or Section 6.3(c), within 45 days following the end of each Quarter, an amount equal to 100% of Available Cash with respect to such Quarter shall be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date following the IPO Closing Date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash distributed by the Partnership to the Partners following the IPO Closing Date pursuant to Section 6.4(b) equals the Operating Surplus from the IPO Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be “Capital Surplus.” Notwithstanding any other provision of this Agreement, all distributions required to be made under this Agreement or otherwise made by the Partnership shall be made subject to Sections 17-607 and 17-804 of the Delaware Act. Notwithstanding any provision to the contrary contained in this Agreement, the Partnership shall not be required to make a distribution to any Partner on account of its interest in the Partnership if such distribution would violate the Delaware Act or any other applicable law.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all cash received during or after the Quarter in which the Liquidation Date occurs, other than from Working Capital Borrowings, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4 Distributions of Available Cash from Operating Surplus.

(a) On the IPO Closing Date. Subject to Section 17-607 of the Delaware Act, on the IPO Closing Date and immediately prior to the commencement of the Subordination Period, the IPO Proceeds and New Credit Facility Proceeds shall be distributed to (x) the General Partner in accordance with its Percentage Interest and (y) AIM Midstream and the LTIP Partners, as Unitholders, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest. The distribution made to AIM Midstream and the General Partner will be a reimbursement for certain capital expenditures incurred with respect to Partnership assets.

(b) During Subordination Period. Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall, subject to Section 17-607 of the Delaware Act and after giving effect to the distributions pursuant to Section 6.4(a), be distributed as follows, except as otherwise contemplated by Section 5.6 in respect of other Partnership Interests or other securities issued pursuant thereto:

(i) First, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s

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Percentage Interest until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Common Unit;

(iii) Third, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(iv) Fourth, to the General Partner and all Unitholders, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(v) Fifth, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v) until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

(vi) Sixth, (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vi), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

(vii) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vii);

provided, however, that if the Target Distributions have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(b)(vii).

(c) After Subordination Period. Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall, subject to Section 17-607 of the Delaware Act, be distributed as follows, except as otherwise required by Section 5.6 in respect of additional Partnership Interests or other securities issued pursuant thereto:

(i) First, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(iii) Third, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iii), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

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(iv) Fourth, (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (A) and (B) of this clause (iv), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

(v) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v);

Section 6.5 Distributions of Available Cash from Capital Surplus.

Available Cash with respect to any Quarter ending on or after the IPO Closing Date that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall, subject to Section 17-607 of the Delaware Act and after giving effect to the distributions pursuant to Section 6.4(a), be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the General Partner and the Unitholders, Pro Rata, until the Minimum Quarterly Distribution has been reduced to zero pursuant to the second sentence of Section 6.6(a). Available Cash that is deemed to be Capital Surplus shall then be distributed (a) to the General Partner in accordance with its Percentage Interest and (b) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

Section 6.6 Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.

(a) The Target Distributions, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Interests. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Target Distributions shall be reduced in the same proportion that the distribution had to the fair market value of the Common Units immediately prior to the announcement of the distribution. If the Common Units are publicly traded on a National Securities Exchange, the fair market value will be the Current Market Price before the ex-dividend date. If the Common Units are not publicly traded, the fair market value will be determined by the Board of Directors.

(b) The Target Distributions shall also be subject to adjustment pursuant to Section 5.11 and Section 6.9.

Section 6.7 Special Provisions Relating to the Holders of Subordinated Units.

(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder with respect to such Common Units issued upon conversion of such Subordinated Units, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such Common Units issued upon conversion of such Subordinated Units shall remain subject to the provisions of Section 5.5(c)(ii), Section 6.1(d)(x)(A), Section 6.7(b) and Section 6.7(c).

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(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Common Unit that has been issued upon conversion of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained Subordinated Units or Retained Converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

(c) A Unitholder holding a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 shall not be issued a Common Unit Certificate pursuant to Section 4.1, if the Common Units are evidenced by Certificates, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and U.S. federal income tax characteristics, in all material respects, to the intrinsic economic and U.S. federal income tax characteristics of an IPO Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Section 5.5(c)(ii), Section 6.1(d)(x), Section 6.7(b); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

Section 6.8 Special Provisions Relating to the Holders of Incentive Distribution Rights.

(a) Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (i) shall (A) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (B) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto and (ii) shall not (A) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (B) be entitled to any distributions other than as provided in Section 6.4(b)(v), Section 6.4(b)(vi) and Section 6.4(b)(vii), Section 6.4(c)(iii), Section 6.4(c)(iv) and Section 6.4(c)(v), and Section 12.4 or (C) be allocated items of income, gain, loss or deduction other than as specified in this Article VI.

(b) The Unitholder holding Common Units that have resulted from the conversion of Incentive Distribution Rights pursuant to Section 5.11 shall not be issued a Common Unit Certificate pursuant to Section 4.1 if the Common Units are evidenced by Certificates, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and U.S. federal income tax characteristics, in all material respects, to the intrinsic economic and U.S. federal income tax characteristics of an IPO Common Unit. In connection with the condition imposed by this Section 6.8(b), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Section 5.5(c)(iii), Section 6.1(d)(x)(B), or Section 6.1(d)(x)(C); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

Section 6.9 Entity-Level Taxation.

If legislation is enacted or the official interpretation of existing legislation is modified by a governmental authority, which after giving effect to such enactment or modification, results in a Group Member becoming subject to federal, state or local or non-U.S. income or withholding taxes in excess of the amount of such taxes due from the Group Member prior to such enactment or modification (including, for the avoidance of doubt, any increase in the rate of such taxation applicable to the Group Member), then the General Partner may, in its sole discretion, reduce the Target Distributions by the amount of income or withholding taxes that are payable by reason of any such new legislation or interpretation (the “Incremental Income Taxes”), or any portion thereof selected by the General Partner, in the manner provided in this Section 6.9. If the General Partner elects to reduce the Target Distributions for any Quarter with respect to all or a portion of any Incremental Income Taxes, the General Partner shall estimate for such Quarter the Partnership Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount”) for all (or the relevant portion of) such Incremental Income Taxes; provided that any difference between such estimate and the actual liability for

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Incremental Income Taxes (or the relevant portion thereof) for such Quarter may, to the extent determined by the General Partner, be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Target Distributions, shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, but without limitation on the ability of the General Partner to delegate its rights and powers to other Persons, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible or exchangeable into Partnership Interests, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if the same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of Partnership cash;

(vii) the selection, employment, retention and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys,

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accountants, consultants and contractors of the General Partner or the Partnership Group and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);

(xiii) the purchase, sale or other acquisition or disposition of Partnership Interests, or the issuance of options, rights, warrants, appreciation rights, tracking and phantom interests or other economic interests in the Partnership or relating to Partnership Interests;

(xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and

(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and each other Person who may acquire an interest in Partnership Interests or in the Partnership or is otherwise bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Underwriting Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement (in each case other than this Agreement, without giving effect to any amendments, supplements or restatements after the date hereof); (ii) agrees that the General Partner (on its own or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Interests or is otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

Section 7.2 Certificate of Limited Partnership.

The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other

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state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3 Restrictions on the General Partner’s Authority.

Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions without the approval of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.4 Reimbursement of the General Partner.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation, employment benefits and other amounts paid to any Person, including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the General Partner or the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7. Any allocation of expenses to the Partnership by Affiliates of the General Partner in a manner consistent with then-applicable accounting and allocation methodologies generally permitted by FERC for rate-making purposes (or in the absence of then-applicable methodologies permitted by FERC, consistent with the most-recently applicable methodologies) and past business practices shall be deemed to be fair and reasonable to the Partnership.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership benefit plans, programs and practices (including the Long Term Incentive Plan and other plans, programs and practices involving the issuance of Partnership Interests or options to purchase or rights, warrants or appreciation rights or phantom or tracking interests or other economic interests in the Partnership or relating to Partnership Interests), or cause the Partnership to issue Partnership Interests or other securities in connection with, or pursuant to, any benefit plan, program or practice maintained or sponsored by the General Partner or any of its Affiliates in each case for the benefit of employees, officers and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests or other securities that the General Partner or such Affiliates are obligated to provide to any employees, officers and directors pursuant to any such benefit plans, programs or practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests or other securities purchased by the General Partner or such Affiliates, from the Partnership or otherwise, to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any

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benefit plans, programs or practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

(d) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.

Section 7.5 Outside Activities.

(a) The General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a Limited Partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement, (B) the acquiring, owning or disposing of debt securities or equity interests in any Group Member or (C) the guarantee of, and mortgage, pledge, or encumbrance of any or all of its assets in connection with, any indebtedness of any Affiliate of the General Partner.

(b) Each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise, to any Group Member or any Partner. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Unrestricted Person.

(c) Subject to the terms of Section 7.5(a) and Section 7.5(b), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of the General Partner or any other Unrestricted Person for the Unrestricted Persons (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Unrestricted Persons shall have no obligation hereunder or as a result of any duty otherwise existing at law, in equity or otherwise, to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person bound by this Agreement for breach of any fiduciary or other duty by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership; provided such Unrestricted Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.

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(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Interests in addition to those acquired on the IPO Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Interests acquired by them. The term “Affiliates” when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e) Notwithstanding anything to the contrary in this Agreement, to the extent that any provision of this Agreement purports or is interpreted to have the effect of restricting or eliminating the fiduciary duties that might otherwise, as a result of Delaware or other applicable law, be owed by the General Partner to the Partnership and its Limited Partners, or to constitute a waiver or consent by the Limited Partners to any such restriction or elimination, such provisions shall be deemed to have been approved by the Partners.

Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may, but shall be under no obligation to, lend to any Group Member, and any Group Member may, but shall be under no obligation to, borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that, in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party, or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party, by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty hereunder or otherwise existing at law, in equity or otherwise, of the General Partner or its Affiliates to the Partnership or the Limited Partners existing hereunder, or existing at law, in equity or otherwise by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner’s Percentage Interest of the total amount distributed to all Partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity; provided, that the Indemnitee shall not be indemnified and held harmless pursuant to this Agreement if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was

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unlawful. Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in appearing at, participating in or defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity, and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates, the Indemnitees and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

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Section 7.8 Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Partners or any other Persons who have acquired interests in the Partnership Interests, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner (in its individual capacity or its capacity as general partner, limited partner or holder of Incentive Distribution Rights) or any of its Affiliates, on the one hand, and the Partnership, any Group Member or, any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty hereunder stated or implied by law or equity or otherwise, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval or Unitholder approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval or Unitholder approval. If Special Approval is sought, then it shall be presumed that, in making its decision, the Conflicts Committee acted in good faith, and if neither Special Approval nor Unitholder approval is sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement and any actions of the General Partner taken in connection therewith are hereby approved by all Partners and shall not constitute a breach of this Agreement or of any duty hereunder or existing at law, in equity or otherwise.

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(b) Whenever the General Partner, the Board of Directors or any committee thereof (including the Conflicts Committee), makes a determination or takes or declines to take any other action, or any of its Affiliates causes the General Partner to do so, in the General Partner’s capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, the Board of Directors, such committee or such Affiliates causing the General Partner to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards (including fiduciary standards) imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must subjectively believe that the determination or other action is in, or not opposed to, the best interests of the Partnership.

(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty (including any fiduciary duty) or obligation whatsoever to the Partnership, any Limited Partner or any other Person bound by this Agreement, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrases, “at the option of the General Partner,” “in its sole discretion” or some variation of those phrases, are used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, or otherwise acts in its capacity as a limited partner or holder of Partnership Interests other than the General Partner Interest, it shall be acting in its individual capacity.

(d) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be in its sole discretion.

(e) Except as expressly set forth in this Agreement, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(f) The Limited Partners hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner may rely upon, and shall be protected in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond,

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debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership or any Group Member.

Section 7.11 Purchase or Sale of Partnership Interests.

The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests; provided that, except as permitted pursuant to Section 4.10, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. As long as Partnership Interests are held by any Group Member, such Partnership Interests shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Interests for its own account, subject to the provisions of Article IV and Article X.

Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner but excluding any individual who is an Affiliate of the General Partner based on such individual’s status as an officer, director or employee of the General Partner or an Affiliate of the General Partner) holds Partnership Interests that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Interests (the “Holder”) to dispose of the number of Partnership Interests it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Interests covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Interests specified by the Holder; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a); and provided further, however, that if the General Partner determines that a postponement of the requested registration would be in the best interests of the Partnership and its Partners due to a pending transaction, investigation or other event, the filing of such registration statement or the effectiveness thereof may be deferred for up to six months, but not thereafter. In connection with any registration pursuant to the immediately preceding sentence, the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Interests subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Interests in such states. Except as set forth in Section 7.12(c),

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all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of Partnership Interests for cash (other than an offering relating solely to a benefit plan), the Partnership shall use all commercially reasonable efforts to include such number or amount of Partnership Interests held by any Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the Partnership Interests of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of Partnership Interests pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder that in their opinion the inclusion of all or some of the Holder’s Partnership Interests would adversely and materially affect the timing or success of the offering, the Partnership shall include in such offering only that number or amount, if any, of Partnership Interests held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Interests were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or issuer free writing prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or any free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d) The provisions of Section 7.12(a) and Section 7.12(b) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Interests with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Interests for which registration was demanded during such two-year period. The provisions of Section 7.12(c) shall continue in effect thereafter.

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(e) The rights to cause the Partnership to register Partnership Interests pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Interests, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Interests with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(f) Any request to register Partnership Interests pursuant to this Section 7.12 shall (i) specify the Partnership Interests intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Interests for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Interests, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Interests.

(g) The Partnership may enter into separate registration rights agreements with the General Partner or any of its Affiliates.

Section 7.13 Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting.

The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures, including Operating Surplus and Adjusted

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Operating Surplus, by making such adjustments to its accrual basis books to account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.

Section 8.2 Fiscal Year.

The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit or other Partnership Interest as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit or other Partnership Interest, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(c) The General Partner shall be deemed to have made a report available to each Record Holder as required by this Section 8.3 if it has either (i) filed such report with the Commission via its Electronic Data Gathering, Analysis and Retrieval system, or any successor system, and such report is publicly available on such system or (ii) made such report available on any publicly available website maintained by the Partnership.

ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information.

The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable period or years that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal, state and local income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for U.S. federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited

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Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(f) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies.

Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

Section 9.4 Withholding.

(a) The General Partner may treat taxes paid by the Partnership on behalf of, all or less than all of the Partners, either as a distribution of cash to such Partners or as a general expense of the Partnership, as determined appropriate under the circumstances by the General Partner.

(b) Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Limited Partners.

(a) The General Partner and AIM Midstream were admitted to the Partnership as Initial Limited Partners on November 4, 2009. The LTIP Partners were admitted to the Partnership as Limited Partners at various dates prior to the date hereof.

(b) A Person shall be admitted as a Limited Partner and shall become bound by the terms of this Agreement if such Person purchases or otherwise lawfully acquires any Limited Partner Interest and becomes the Record Holder of such Limited Partner Interests in accordance with the provisions of Article IV or Article V. A Person may become a Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected on the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.9. Upon the issuance by the Partnership of Common Units to the Underwriters as described in Section 5.3 in connection with the Initial Public Offering, the Underwriters will automatically be admitted to the Partnership as Limited Partners in respect of the Common Units issued to them.

(c) The name and mailing address of each Record Holder shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the

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information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.

(d) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(b).

Section 10.2 Admission of Successor General Partner.

A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest (represented by Notional General Partner Units) pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or the transfer of the General Partner Interest (represented by Notional General Partner Units) pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor is hereby authorized to and shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership.

To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);

(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its General Partner Interest pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

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(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv), Section 11.1(a)(v), Section 11.1(a)(vi)(A), Section 11.1(a)(vi)(B), Section 11.1(a)(vi)(C) or Section 11.1(a)(vi)(E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time before 12:00 midnight, Central Time, on June 30, 2021, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or any Group Member or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, Central Time, on June 30, 2021, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal, the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal pursuant to Section 11.1(a)(i), a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1 unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

Section 11.2 Removal of the General Partner.

The General Partner may be removed if such removal is approved by the Unitholders holding at least 662/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the Outstanding Common Units, voting as a separate class and a majority of the Outstanding Subordinated Units (if any Subordinated Units are then Outstanding) voting as a separate class (including, in each case, Units held by the General

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Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates’ general partner interest (or equivalent interest), if any, in the other Group Members and all of its or its Affiliates’ Incentive Distribution Rights (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the value of the Units, including the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner, the value of the Incentive Distribution Rights and the General Partner Interest and other factors it may deem relevant.

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(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (and its Affiliates, if applicable) shall become a Limited Partner and the Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest to Common Units will be characterized as if the Departing General Partner (and its Affiliates, if applicable) contributed the Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner Interest of the Departing General Partner by (B) a percentage equal to 100% less the Percentage Interest of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled in respect of its General Partner Interest. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.4 Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages.

Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal, (i) the Subordination Period will end and all Outstanding Subordinated Units will immediately and automatically convert into Common Units on a one-for-one basis (provided, however, that such converted Subordinated Units shall remain subject to the provisions of Section 5.5(c)(ii), Section 6.1(d)(x) and Section 6.7(c)), (ii) all Cumulative Common Unit Arrearages on the Common Units will be extinguished and (iii) the General Partner will have the right to convert its General Partner Interest (represented by Notional General Partner Units) and its Incentive Distribution Rights into Common Units or to receive cash in exchange therefor in accordance with Section 11.3.

Section 11.5 Withdrawal of Limited Partners.

No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution.

The Partnership shall not be dissolved by the admission of Additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, Section 11.2 or Section 12.2, the Partnership shall not be dissolved and such successor General Partner is

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hereby authorized to, and shall, continue the business of the Partnership. Subject to Section 12.2, the Partnership shall dissolve, and its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a), unless a successor is admitted to the Partnership pursuant to this Agreement;

(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution.

Upon an Event of Withdrawal caused by (a) the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or Section 11.1(a)(iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), Section 11.1(a)(v) or Section 11.1(a)(vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing, effective as of the date of the Event of Withdrawal, as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;

provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability under the Delaware Act of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator.

Upon dissolution of the Partnership, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, if any, voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such

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successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4 Liquidation.

The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be applied as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership.

Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions.

The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

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Section 12.7 Waiver of Partition.

To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration.

No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable period of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT;

MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner.

Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) the admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(d) a change that the General Partner determines, (i) does not adversely affect in any material respect the Limited Partners considered as a whole or any particular class of Partnership Interests as compared to other classes of Partnership Interests, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable period of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable period of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

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(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of any class or series of Partnership Interests and options, rights, warrants, appreciation rights, tracking and phantom interests or other economic interests in the Partnership relating to Partnership Interests pursuant to Section 5.6, including any amendment that the General Partner determines is necessary or appropriate in connection with (i) the adjustments of the Target Distributions pursuant to the provisions of Section 5.11, (ii) the implementation of the provisions of Section 5.11 or (iii) any modifications to the Incentive Distribution Rights made in connection with the issuance of Partnership Interests pursuant to Section 5.6, provided that, with respect to this clause (iii), the modifications to the Incentive Distribution Rights and the related issuance of Partnership Interests have received Special Approval;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4 or Section 7.1(a);

(k) a merger, conveyance or conversion pursuant to Section 14.3(d); or

(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures.

Except as provided in Section 13.1 and Section 13.3, all amendments to this Agreement shall be made in accordance with the requirements contained in this Section 13.2. Amendments to this Agreement may be proposed only by the General Partner; provided, however, that, to the full extent permitted by law, the General Partner shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so free of any duty (including any fiduciary duty) or obligation whatsoever to the Partnership, any Limited Partner, or any other Person bound by this Agreement and, in declining to propose or approve an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and, except as otherwise provided by Section 13.1 and Section 13.3, the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has either (i) filed such amendment with the Commission via its Electronic Data Gathering, Analysis and Retrieval system, or any successor system, and such amendment is publicly available on such system or (ii) made such amendment available on any publicly available website maintained by the Partnership.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) or requires a vote or approval of Partners (or a subset of the Partners) holding a specified Percentage Interest required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of in the case of any provision of this Agreement other than Section 11.2 or Section 13.4, reducing such percentage, unless such amendment is approved by the written consent or the affirmative vote of

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holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced or increased, as applicable or the affirmative vote of Partners whose aggregate Percentage Interest constitutes not less than the voting requirement sought to be reduced, as applicable.

(b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of (including requiring any holder of a class of Partnership Interests to make additional Capital Contributions to the Partnership) any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict, change or modify in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Section 14.3 and Section 13.1 (this Section 13.3(c) being subject to the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners as contemplated in Section 13.1), any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected. If the General Partner determines an amendment does not satisfy the requirements of Section 13.1(d)(i) because it adversely affects one or more classes of Partnership Interests, as compared to other classes of Partnership Interests, in any material respect, such amendment shall only be required to be approved by the adversely affected class or classes.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Percentage Interests of all Limited Partners voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of Partners (including the General Partner and its Affiliates) holding at least 90% of the Percentage Interests of all Limited Partners.

Section 13.4 Special Meetings.

All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 16.1. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting.

Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication

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in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6 Record Date.

For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Adjournment.

When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business that might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes.

The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9 Quorum and Voting.

The holders of a majority, by Percentage Interest, of the Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Partners of such class or classes unless any such action by the Partners requires approval by holders of a greater Percentage Interest, in which case the quorum shall be such greater Percentage Interest. At any meeting of the Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Partners holding Partnership Interests that in the aggregate represent a majority of the Percentage Interest of those present in person or by proxy at such meeting shall be deemed to constitute the act of all Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Partners holding Partnership Interests that in the aggregate represent at least such greater or different percentage shall be required; provided, however, that if, as a matter of law or amendment to this Agreement, approval by plurality vote of Partners (or any class thereof) is required to approve any action, no minimum quorum shall be required. The Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Partners to

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leave less than a quorum, if any action taken (other than adjournment) is approved by Partners holding the required Percentage Interest specified in this Agreement. In the absence of a quorum any meeting of Partners may be adjourned from time to time by the affirmative vote of Partners with at least a majority, by Percentage Interest, of the Partnership Interests entitled to vote at such meeting (including Partnership Interests deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10 Conduct of a Meeting.

The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting.

If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting, without a vote and without prior notice, if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage, by Percentage Interest, of the Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner), as the case may be, that would be necessary to authorize or take such action at a meeting at which all the Limited Partners entitled to vote at such meeting were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot, if any, submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner and (b) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners. Nothing contained in this Section 13.11 shall be deemed to require the General Partner to solicit all Limited Partners in connection with a matter approved by the holders of the requisite Percentage Interest acting by written consent without a meeting.

Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as

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to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER, CONSOLIDATION OR CONVERSION

Section 14.1 Authority.

The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) the name and jurisdiction of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity interests of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity, then the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) that the holders of such interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of equity interests represented by certificates, upon the surrender of such certificates, which cash, property or interests, rights, securities or obligations of the Surviving Business Entity or any general or

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limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, certificate of formation or limited liability company agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.5 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain and stated in the certificate of merger); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

(i) the name of the converting entity and the converted entity;

(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

(iv) the manner and basis of exchanging or converting the equity interests or other rights or securities of the converting entity for, or into, cash, property, rights, securities or interests of the converted entity, or, in addition to or in lieu thereof, cash, property, rights, securities or interests of another entity;

(v) in an attachment or exhibit, the certificate of conversion; and

(vi) in an attachment or exhibit, the articles of incorporation or other organizational documents of the converted entity;

(vii) the effective time of the conversion, which may be the date of the filing of the certificate of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such certificate of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of conversion and stated therein); and

(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Limited Partners.

(a) Except as provided in Section 14.3(d), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Section 14.3(d) and Section 14.3(e), the Merger Agreement or the Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or the Plan of Conversion, as the case may be,

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effects an amendment to any provision of this Agreement that, if contained in an amendment to this Agreement adopted pursuant to Article XIII, would require for its approval the vote or consent of the holders of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or the Plan of Conversion, as the case may be.

(c) Except as provided in Section 14.3(d) and Section 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 14.5, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or the Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such merger, conveyance or conversion other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the merger, conveyance or conversion, as the case may be, would not result in the loss of the limited liability of any Limited Partner as compared to its limited liability under the Delaware Act or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (ii) the sole purpose of such merger, conveyance or conversion is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the General Partner determines that the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner as compared to its limited liability under the Delaware Act or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Partnership Interest outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Partnership Interest of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests (other than the Incentive Distribution Rights) Outstanding immediately prior to the effective date of such merger or consolidation.

Section 14.4 Amendment of Partnership Agreement.

Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.4 shall be effective at the effective time or date of the merger or consolidation.

Section 14.5 Certificate of Merger or Certificate of Conversion.

Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

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Section 14.6 Effect of Merger, Consolidation or Conversion.

(a) At the effective time of the merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) At the effective time of the conversion:

(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

(iv) all rights of creditors or other parties with respect to or against the interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

(v) a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior partners without any need for substitution of parties; and

(vi) the Partnership Units or other rights, securities or interests of the Partnership that are to be converted into cash, property, rights, securities or interests in the converted entity, or rights, securities or interests in any other entity, as provided in the Plan of Conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable in its sole discretion, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the

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date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class or classes (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests.

(c) In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

ARTICLE XVI

GENERAL PROVISIONS

Section 16.1 Addresses and Notices; Written Communications.

(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to

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make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report given or made in accordance with the provisions of this Section 16.1 is returned marked to indicate that such notice, payment or report was unable to be delivered, such notice, payment or report and, in the case of notices, payments or reports returned by the United States Postal Service (or other physical mail delivery mail service outside the United States of America), any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) or other delivery if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms “in writing”, “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 16.2 Further Action.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 16.3 Binding Effect.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4 Integration.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Third-Party Beneficiaries.

Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or

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privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

Section 16.8 Counterparts.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement (a) immediately upon affixing its signature hereto, (b) in the case of the General Partner and the holders of Limited Partner Interests outstanding immediately prior to the closing of the Initial Public Offering, immediately upon the closing of the Initial Public Offering, without the execution hereof, or (c) in the case of a Person acquiring a Limited Partner Interest pursuant to Section 10.1(b), immediately upon the acquisition of such Limited Partner Interest, without execution hereof.

Section 16.9 Applicable Law; Forum; Venue and Jurisdiction; Waiver of Trial by Jury.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of duty (including any fiduciary duty) owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to or to interpret or enforce any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine, shall be exclusively brought in the Court of Chancery of the State of Delaware, in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;

(ii) irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claim, suit, action or proceeding;

(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding;

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in clause (v) hereof shall affect or limit any right to serve process in any other manner permitted by law; and

(vi) IRREVOCABLY WAIVES THE RIGHT TO TRIAL BY JURY IN ANY ACTION TO ENFORCE OR INTERPRET THE PROVISIONS OF THIS AGREEMENT.

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Section 16.10 Invalidity of Provisions.

If any provision or part of a provision of this Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and part thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision or part reformed so that it would be valid, legal and enforceable to the maximum extent possible.

Section 16.11 Consent of Partners.

Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner and each other Person bound by the provisions of this Agreement shall be bound by the results of such action.

Section 16.12 Facsimile Signatures.

The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on Certificates representing Common Units is expressly permitted by this Agreement.

ARTICLE XVII

CERTAIN TRANSACTIONS IN CONNECTION WITH THE INITIAL PUBLIC OFFERING

Section 17.1 Non-Pro Rata Redemption of Common Units.

The General Partner is authorized to use the proceeds from any exercise by the Underwriters of the Over-Allotment Option in the Initial Public Offering to redeem from AIM Midstream, but not from other Partners, that number of Common Units that corresponds to the number of Common Units issued upon such exercise at a price per Common Unit equal to the price per Common Unit received by the Partnership for the Common Units issued to the Underwriters upon such exercise. The distribution of the proceeds from such exercise to AIM Midstream will be a reimbursement for certain capital expenditures incurred with respect to Partnership assets.

[REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK.]

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ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:


TEN COM —	as tenants in common
		UNIF GIFT/TRANSFERS MIN ACT
TEN ENT —	as tenants by the entireties		Custodian
		(Cust)		(Minor)
JT TEN —	as joint tenants with right of survivorship and not as tenants in common	under Uniform Gifts/Transfers to CD Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto




(Please print or typewrite name and address of assignee)		(Please insert Social Security or other identifying number of assignee)

Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of American Midstream Partners, LP


Date:		NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15		(Signature) (Signature)

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration.

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APPENDIX B

Glossary of Terms

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf/d: One billion cubic feet per day.

condensate: A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

end-use markets: The ultimate users and consumers of transported energy products.

FERC: Federal Energy Regulatory Commission.

gal: One gallon.

gal/d: One gallon per day.

Mcf: One thousand cubic feet.

Mgal/d: One thousand gallons per day.

MMBbl/d: One million stock tank barrels per day.

MMBtu: One million British Thermal Units.

MMBtu/d: One million British Thermal Units per day.

MMcf: One million cubic feet.

MMcf/d: One million cubic feet per day.

NGA: Natural Gas Act of 1938.

NGLs: Natural gas liquids. The combination of ethane, propane, normal butane, iso-butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

OPIS: Oil Price Information Service.

play: A proven geological formation that contains commercial amounts of hydrocarbons.

receipt point: The point where production is received by or into a gathering system or transportation pipeline.

residue gas: The natural gas remaining after being processed or treated.

tailgate: Refers to the point at which processed natural gas and natural gas liquids leave a processing facility for end-use markets.

Tcf: One trillion cubic feet.

throughput: The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

wellhead: The equipment at the surface of a well used to control the well’s pressure; also, the point at which the hydrocarbons and water exit the ground.

WTI: West Texas Intermediate, a type of crude oil commonly used as a price benchmark.

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PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

Set forth below are the expenses (other than underwriting discounts, commissions and structuring fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.


SEC registration fee	$	10,015
FINRA filing fee		9,125
NYSE listing fee		125,000
Printing and engraving expenses		600,000
Fees and expenses of legal counsel		1,250,000
Accounting fees and expenses		900,000
Transfer agent and registrar fees		10,000
Miscellaneous		345,860	(1)

Total	$	3,250,000


(1)		American Midstream Partners estimates that it will reimburse the underwriters approximately $83,000 for expenses they incur in connection with the roadshow.


Item 14.	*Indemnification of Directors and Officers.*

American Midstream Partners, LP

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of American Midstream Partners, LP and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

American Midstream GP, LLC

Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):


	•	any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

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	•	any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;

	•	any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and

	•	any person designated by our general partner.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.


Item 15.	*Recent Sales of Unregistered Securities.*

On November 4, 2009, in connection with our formation, we issued (i) 200,000 general partner units representing a 2.0% general partner interest in us and all of our incentive distribution rights to our general partner in exchange for $2.0 million and (ii) 9,800,000 common units representing a 98.0% limited partner interest in us to AIM Midstream Holdings in exchange for $98.0 million. These transactions were exempt from registration under Section 4(2) of the Securities Act as they did not involve a public offering.

On September 27, 2010, we issued (i) 10,000 general partner units to our general partner in exchange for $100,000 and (ii) 490,000 common units to AIM Midstream Holdings in exchange for $4.9 million. These transactions were exempt from registration under Section 4(2) of the Securities Act as they did not involve a public offering.

On November 3, 2010, we issued (i) 14,000 general partner units to our general partner in exchange for $140,000 and (ii) 686,000 common units to AIM Midstream Holdings in exchange for $6.9 million. These transactions were exempt from registration under Section 4(2) of the Securities Act as they did not involve a public offering.


Item 16.	*Exhibits and Financial Schedules.*

The following documents are filed as exhibits to this registration statement:


Number			Description


	1	.1**	Form of Underwriting Agreement

	3	.1**	Certificate of Limited Partnership of American Midstream Partners, LP

	3	.2**	Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP

	3	.3**	Form of Second Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP (Included as Appendix A to the Prospectus)

	3	.4**	Certificate of Formation of American Midstream GP, LLC

	3	.5**	Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC

	3	.6**	Form of First Amendment to Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC

	5	.1**	Opinion of Andrews Kurth LLP as to the legality of the securities being registered

	8	.1**	Opinion of Andrews Kurth LLP relating to tax matters

	10	.1**	Revolving and Term Loan Credit Agreement, dated as of October 5, 2009, by and among American Midstream, LLC, as the initial borrower, Comerica Bank, as the administrative agent, BBVA Compass Bank, as the documentation agent and Comerica Bank and BBVA Compass Bank as co-lead arrangers.

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Number			Description


	10	.2**	First Amendment to Revolving and Term Loan Credit Agreement, dated effective as of October 5, 2009, among American Midstream, LLC, American Midstream Marketing, LLC, American Midstream (Alabama Gathering), LLC, American Midstream (Alabama Intrastate), LLC, American Midstream (Alatenn), LLC, American Midstream (Midla), LLC, American Midstream (Mississippi), LLC, American Midstream (Tennessee River), LLC, American Midstream Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC, American Midstream (Louisiana Intrastate), LLC, American Midstream (Sigco Intrastate), LLC and American Midstream Offshore (Seacrest) LP, as borrowers, the Lenders named therein, and Comerica Bank, as administrative agent.

	10	.3**	Second Amendment and Waiver to Revolving and Term Loan Credit Agreement, dated July 30, 2010, among American Midstream, LLC, American Midstream Marketing, LLC, American Midstream (Alabama Gathering), LLC, American Midstream (Alabama Intrastate), LLC, American Midstream (Alatenn), LLC, American Midstream (Midla), LLC American Midstream (Mississippi), LLC, American Midstream (Tennessee River), LLC, American Midstream Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC, American Midstream (Louisiana Intrastate), LLC, American Midstream (Sigco Intrastate), LLC And American Midstream Offshore (Seacrest) LP, the Lenders named therein), and Comerica Bank, as administrative agent.

	10	.4**	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and Brian Bierbach.

	10	.5**	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and Marty W. Patterson.

	10	.6**	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and John J. Connor II.

	10	.7**	Amended and Restated American Midstream GP, LLC Long-Term Incentive Plan.

	10	.8**	Form of Phantom Unit Grant under American Midstream GP, LLC Long-Term Incentive Plan.

	10	.9	Gas Processing Agreement, dated effective June 1, 2011, by and between American Midstream (Louisiana Intrastate), LLC and Enterprise Gas Processing, LLC.

	10	.10**†	Firm Gas Gathering Agreement, dated as of August 1, 2008, by and between American Midstream Offshore (Seacrest) LP, and Contango Resources Company.

	10	.11**	Letter Agreement, dated December 10, 2009, between American Midstream Offshore (Seacrest) LP and Contango Operators, Inc.

	10	.12**†	Base Contract for Sale and Purchase of Natural Gas, dated June 1, 2010, between ExxonMobil Gas & Power Marketing Company and Mid Louisiana Gas Transmission, LLC

	10	.13**†	Gas Processing Agreement, dated July 14, 2010, by and between American Midstream (Mississippi), LLC and Venture Oil & Gas, Inc.

	10	.14**	Gas Transportation Contract, dated as of November 1, 1997, by and between Midcoast Interstate Transmission, Inc. and the City of Decatur Utilities.

	10	.15**	Amendment No. 1 to Gas Transportation Contract, dated November 1, 2003, by and between Enbridge Pipeline (Alatenn), Inc. and The City of Decatur, Alabama.

	10	.16**	Natural Gas Pipeline Construction and Transportation Agreement, dated effective as of June 28, 2000, by and between Bamagas Company and Calpine Energy Services, L.P.

	10	.17**	First Amendment to Natural Gas Pipeline Construction and Transportation Agreement, dated as of September 1, 2001, by and between Bamagas Company and Calpine Energy Services, L.P.

	10	.18**	Natural Gas Pipeline Construction and Transportation Agreement, dated effective as of June 28, 2000, by and between Bamagas Company and Calpine Energy Services, L.P.

	10	.19**	First Amendment to Natural Gas Pipeline Construction and Transportation Agreement, dated as of September 1, 2001, by and between Bamagas Company and Calpine Energy Services, L.P.

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Number			Description


	10	.20**	Agreement, dated as of May 1, 2003, by and between Enbridge Pipelines (AlaTenn), L.L.C. and City of Huntsville.

	10	.21**	Service Agreement, dated September 1, 2008, by and between Enbridge Pipelines (Midla) L.L.C. and Enbridge Marketing (US), LP.

	10	.22**	Service Agreement, dated September 1, 2008, by and between Enbridge Pipelines (Midla) L.L.C. and Enbridge Marketing (US), LP.

	10	.23**	Gas Processing Agreement, dated July 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing, LLC.

	10	.24**	Gas Processing Agreement, dated November 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing.

	10	.25**	Gas Processing Agreement, dated April 1, 2011, by and between American Midstream (Louisiana Intrastate), LLC and Enterprise Gas Processing, LLC.

	10	.26**	Employment Agreement, dated June 8, 2011, by and between American Midstream GP, LLC and Sandra M. Flower.

	10	.27**	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and William B. Mathews.

	10	.28**	Form of Amendment of Grant of Phantom Units under the American Midstream Partners, LP Long-Term Incentive Plan.

	10	.29**	Form of Credit Agreement.

	21	.1**	List of Subsidiaries of American Midstream Partners, LP.

	23	.1	Consent of PricewaterhouseCoopers LLP.

	23	.2	Consent of PricewaterhouseCoopers LLP.

	23	.3**	Form of consent of Andrews Kurth LLP (contained in Exhibit 5.1).

	23	.4**	Form of consent of Andrews Kurth LLP (contained in Exhibit 8.1).

	24	.1**	Powers of Attorney (contained on the signature page to this Registration Statement).


*		To be filed by amendment.

**		Previously filed.

†		Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.


Item 17.	*Undertakings*

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

II-4

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(4) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with American Midstream GP, our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to American Midstream GP or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The undersigned registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

II-5

EXHIBIT INDEX


Number			Description

	1	.1**	Form of Underwriting Agreement
	3	.1**	Certificate of Limited Partnership of American Midstream Partners, LP
	3	.2**	Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP
	3	.3**	Form of Second Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP (Included as Appendix A to the Prospectus)
	3	.4**	Certificate of Formation of American Midstream GP, LLC
	3	.5**	Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC
	3	.6**	Form of First Amendment to Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC
	5	.1**	Opinion of Andrews Kurth LLP as to the legality of the securities being registered
	8	.1**	Opinion of Andrews Kurth LLP relating to tax matters
	10	.1**	Revolving and Term Loan Credit Agreement, dated as of October 5, 2009, by and among American Midstream, LLC, as the initial borrower, Comerica Bank, as the administrative agent, BBVA Compass Bank, as the documentation agent and Comerica Bank and BBVA Compass Bank as co-lead arrangers.
	10	.2**	First Amendment to Revolving and Term Loan Credit Agreement, dated effective as of October 5, 2009, among American Midstream, LLC, American Midstream Marketing, LLC, American Midstream (Alabama Gathering), LLC, American Midstream (Alabama Intrastate), LLC, American Midstream (Alatenn), LLC, American Midstream (Midla), LLC, American Midstream (Mississippi), LLC, American Midstream (Tennessee River), LLC, American Midstream Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC, American Midstream (Louisiana Intrastate), LLC, American Midstream (Sigco Intrastate), LLC and American Midstream Offshore (Seacrest) LP, as borrowers, the Lenders named therein, and Comerica Bank, as administrative agent.
	10	.3**	Second Amendment and Waiver to Revolving and Term Loan Credit Agreement, dated July 30, 2010, among American Midstream, LLC, American Midstream Marketing, LLC, American Midstream (Alabama Gathering), LLC, American Midstream (Alabama Intrastate), LLC, American Midstream (Alatenn), LLC, American Midstream (Midla), LLC American Midstream (Mississippi), LLC, American Midstream (Tennessee River), LLC, American Midstream Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC, American Midstream (Louisiana Intrastate), LLC, American Midstream (Sigco Intrastate), LLC And American Midstream Offshore (Seacrest) LP, the Lenders named therein), and Comerica Bank, as administrative agent.
	10	.4**	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and Brian Bierbach.
	10	.5**	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and Marty W. Patterson.
	10	.6**	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and John J. Connor II.
	10	.7**	Amended and Restated American Midstream GP, LLC Long-Term Incentive Plan.
	10	.8**	Form of Phantom Unit Grant under American Midstream GP, LLC Long-Term Incentive Plan.
	10	.9	Gas Processing Agreement, dated effective June 1, 2011, by and between American Midstream (Louisiana Intrastate), LLC and Enterprise Gas Processing, LLC.
	10	.10**†	Firm Gas Gathering Agreement, dated as of August 1, 2008, by and between American Midstream Offshore (Seacrest) LP, and Contango Resources Company.


Number			Description

	10	.11**	Letter Agreement, dated December 10, 2009, between American Midstream Offshore (Seacrest) LP and Contango Operators, Inc.
	10	.12**†	Base Contract for Sale and Purchase of Natural Gas, dated June 1, 2010, between ExxonMobil Gas & Power Marketing Company and Mid Louisiana Gas Transmission, LLC
	10	.13**†	Gas Processing Agreement, dated July 14, 2010, by and between American Midstream (Mississippi), LLC and Venture Oil & Gas, Inc.
	10	.14**	Gas Transportation Contract, dated as of November 1, 1997, by and between Midcoast Interstate Transmission, Inc. and the City of Decatur Utilities.
	10	.15**	Amendment No. 1 to Gas Transportation Contract, dated November 1, 2003, by and between Enbridge Pipeline (Alatenn), Inc. and The City of Decatur, Alabama.
	10	.16**	Natural Gas Pipeline Construction and Transportation Agreement, dated effective as of June 28, 2000, by and between Bamagas Company and Calpine Energy Services, L.P.
	10	.17**	First Amendment to Natural Gas Pipeline Construction and Transportation Agreement, dated as of September 1, 2001, by and between Bamagas Company and Calpine Energy Services, L.P.
	10	.18**	Natural Gas Pipeline Construction and Transportation Agreement, dated effective as of June 28, 2000, by and between Bamagas Company and Calpine Energy Services, L.P.
	10	.19**	First Amendment to Natural Gas Pipeline Construction and Transportation Agreement, dated as of September 1, 2001, by and between Bamagas Company and Calpine Energy Services, L.P.
	10	.20**	Agreement, dated as of May 1, 2003, by and between Enbridge Pipelines (AlaTenn), L.L.C. and City of Huntsville.
	10	.21**	Service Agreement, dated September 1, 2008, by and between Enbridge Pipelines (Midla) L.L.C. and Enbridge Marketing (US), LP.
	10	.22**	Service Agreement, dated September 1, 2008, by and between Enbridge Pipelines (Midla) L.L.C. and Enbridge Marketing (US), LP.
	10	.23**	Gas Processing Agreement, dated July 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing, LLC.
	10	.24**	Gas Processing Agreement, dated November 1, 2010, by and between American Midstream, LLC and Enterprise Gas Processing.
	10	.25**	Gas Processing Agreement, dated April 1, 2011, by and between American Midstream (Louisiana Intrastate), LLC and Enterprise Gas Processing, LLC.
	10	.26**	Employment Agreement, dated June 8, 2011, by and between American Midstream GP, LLC and Sandra M. Flower.
	10	.27**	Employment Agreement, dated June 9, 2011, by and between American Midstream GP, LLC and William B. Mathews.
	10	.28**	Form of Amendment of Grant of Phantom Units under the American Midstream Partners, LP Long-Term Incentive Plan.
	10	.29**	Form of Credit Agreement.
	21	.1**	List of Subsidiaries of American Midstream Partners, LP.
	23	.1	Consent of PricewaterhouseCoopers LLP.
	23	.2	Consent of PricewaterhouseCoopers LLP.
	23	.3**	Form of consent of Andrews Kurth LLP (contained in Exhibit 5.1).
	23	.4**	Form of consent of Andrews Kurth LLP (contained in Exhibit 8.1).
	24	.1**	Powers of Attorney (contained on the signature page to this Registration Statement).


	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


	Page

American Midstream Partners, LP
Historical Unaudited Consolidated Financial Statements as of and for the Three Months Ended March 31, 2010 and March 31, 2011
Unaudited Consolidated Balance Sheets		F-2
Unaudited Consolidated Statements of Operations		F-3
Unaudited Consolidated Statements of Changes in Partners’ Capital		F-4
Unaudited Consolidated Statements of Cash Flows		F-5
Notes to Unaudited Consolidated Financial Statements		F-6
Historical Consolidated Financial Statements as of December 31, 2009 and 2010 and for the Period From August 20, 2009 (Inception Date) to December 31, 2009 and the Year Ended December 31, 2010
Report of Independent Registered Public Accounting Firm		F-21
Consolidated Balance Sheets		F-22
Consolidated Statements of Operations		F-23
Consolidated Statements of Changes in Partners’ Capital		F-24
Consolidated Statements of Cash Flows		F-25
Notes to Consolidated Financial Statements		F-26
American Midstream Partners Predecessor
Historical Combined Financial Statements as of December 31, 2008 and October 31, 2009 and for the Year Ended December 31, 2008 and the Ten Months Ended October 31, 2009
Report of Independent Registered Public Accounting Firm		F-52
Combined Balance Sheets		F-53
Combined Statements of Operations		F-54
Combined Statements of Group Equity		F-55
Combined Statements of Cash Flows		F-56
Notes to Combined Financial Statements		F-57


	(in thousands)

Group equity at December 31, 2007	$	145,833
Contributions by parent		10,500
Distributions to parent		(7,245	)
Other comprehensive loss		(17	)
Net income		2,728

Group equity at December 31, 2008	$	151,799
Contributions by parent		111,103
Distributions to parent		(25,772	)
Other comprehensive loss		(201	)
Net loss		(5,337	)

Group equity at October 31, 2009	$	231,592


ARTICLE I DEFINITIONS		A-1
Section 1.1	Definitions	A-1
Section 1.2	Construction	A-20
ARTICLE II ORGANIZATION		A-20
Section 2.1	Formation	A-20
Section 2.2	Name	A-20
Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices	A-20
Section 2.4	Purpose and Business	A-21
Section 2.5	Powers	A-21
Section 2.6	Term	A-21
Section 2.7	Title to Partnership Assets	A-21
ARTICLE III RIGHTS OF LIMITED PARTNERS		A-22
Section 3.1	Limitation of Liability	A-22
Section 3.2	Management of Business	A-22
Section 3.3	Outside Activities of the Limited Partners	A-22
Section 3.4	Rights of Limited Partners	A-22
ARTICLE IV CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS		A-23
Section 4.1	Certificates	A-23
Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates	A-23
Section 4.3	Record Holders	A-24
Section 4.4	Transfer Generally	A-24
Section 4.5	Registration and Transfer of Limited Partner Interests	A-24
Section 4.6	Transfer of the General Partner’s General Partner Interest	A-25
Section 4.7	Transfer of Incentive Distribution Rights	A-26
Section 4.8	Restrictions on Transfers	A-26
Section 4.9	Eligibility Certifications; Ineligible Holders	A-26
Section 4.10	Redemption of Partnership Interests of Ineligible Holders	A-27
ARTICLE V CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS		A-28
Section 5.1	Intentionally Omitted	A-28
Section 5.2	Contributions by the General Partner and the Initial Limited Partners	A-28
Section 5.3	Contributions by Limited Partners	A-28
Section 5.4	Interest and Withdrawal of Capital Contributions	A-29
Section 5.5	Capital Accounts	A-29
Section 5.6	Issuances of Additional Partnership Interests	A-31
Section 5.7	Conversion of Subordinated Units	A-32
Section 5.8	Limited Preemptive Right	A-32
Section 5.9	Splits and Combinations	A-32
Section 5.10	Fully Paid and Non-Assessable Nature of Limited Partner Interests	A-33
Section 5.11	Issuance of Common Units in Connection with Reset of Incentive Distribution Rights	A-33
ARTICLE VI ALLOCATIONS AND DISTRIBUTIONS		A-35
Section 6.1	Allocations for Capital Account Purposes	A-35


Section 6.2	Allocations for Tax Purposes	A-42
Section 6.3	Requirement and Characterization of Distributions; Distributions to Record Holders	A-43
Section 6.4	Distributions of Available Cash from Operating Surplus	A-43
Section 6.5	Distributions of Available Cash from Capital Surplus	A-45
Section 6.6	Adjustment of Minimum Quarterly Distribution and Target Distribution Levels	A-45
Section 6.7	Special Provisions Relating to the Holders of Subordinated Units	A-45
Section 6.8	Special Provisions Relating to the Holders of Incentive Distribution Rights	A-46
Section 6.9	Entity-Level Taxation	A-46
ARTICLE VII MANAGEMENT AND OPERATION OF BUSINESS		A-47
Section 7.1	Management	A-47
Section 7.2	Certificate of Limited Partnership	A-48
Section 7.3	Restrictions on the General Partner’s Authority	A-49
Section 7.4	Reimbursement of the General Partner	A-49
Section 7.5	Outside Activities	A-50
Section 7.6	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members	A-51
Section 7.7	Indemnification	A-51
Section 7.8	Liability of Indemnitees	A-53
Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties	A-53
Section 7.10	Other Matters Concerning the General Partner	A-54
Section 7.11	Purchase or Sale of Partnership Interests	A-55
Section 7.12	Registration Rights of the General Partner and its Affiliates	A-55
Section 7.13	Reliance by Third Parties	A-57
ARTICLE VIII BOOKS, RECORDS, ACCOUNTING AND REPORTS		A-57
Section 8.1	Records and Accounting	A-57
Section 8.2	Fiscal Year	A-58
Section 8.3	Reports	A-58
ARTICLE IX TAX MATTERS		A-58
Section 9.1	Tax Returns and Information	A-58
Section 9.2	Tax Elections	A-58
Section 9.3	Tax Controversies	A-59
Section 9.4	Withholding	A-59
ARTICLE X ADMISSION OF PARTNERS		A-59
Section 10.1	Admission of Limited Partners	A-59
Section 10.2	Admission of Successor General Partner	A-60
Section 10.3	Amendment of Agreement and Certificate of Limited Partnership	A-60
ARTICLE XI WITHDRAWAL OR REMOVAL OF PARTNERS		A-60
Section 11.1	Withdrawal of the General Partner	A-60
Section 11.2	Removal of the General Partner	A-61
Section 11.3	Interest of Departing General Partner and Successor General Partner	A-62
Section 11.4	Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages	A-63

Section 11.5	Withdrawal of Limited Partners	A-63


ARTICLE XII DISSOLUTION AND LIQUIDATION		A-63
Section 12.1	Dissolution	A-63
Section 12.2	Continuation of the Business of the Partnership After Dissolution	A-64
Section 12.3	Liquidator	A-64
Section 12.4	Liquidation	A-65
Section 12.5	Cancellation of Certificate of Limited Partnership	A-65
Section 12.6	Return of Contributions	A-65
Section 12.7	Waiver of Partition	A-66
Section 12.8	Capital Account Restoration	A-66
ARTICLE XIII AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE		A-66
Section 13.1	Amendments to be Adopted Solely by the General Partner	A-66
Section 13.2	Amendment Procedures	A-67
Section 13.3	Amendment Requirements	A-67
Section 13.4	Special Meetings	A-68
Section 13.5	Notice of a Meeting	A-68
Section 13.6	Record Date	A-69
Section 13.7	Adjournment	A-69
Section 13.8	Waiver of Notice; Approval of Meeting; Approval of Minutes	A-69
Section 13.9	Quorum and Voting	A-69
Section 13.10	Conduct of a Meeting	A-70
Section 13.11	Action Without a Meeting	A-70
Section 13.12	Right to Vote and Related Matters	A-70
ARTICLE XIV MERGER, CONSOLIDATION OR CONVERSION		A-71
Section 14.1	Authority	A-71
Section 14.2	Procedure for Merger, Consolidation or Conversion	A-71
Section 14.3	Approval by Limited Partners	A-72
Section 14.4	Amendment of Partnership Agreement	A-73
Section 14.5	Certificate of Merger or Articles of Conversion	A-73
Section 14.6	Effect of Merger, Consolidation or Conversion	A-74
ARTICLE XV RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS		A-74
Section 15.1	Right to Acquire Limited Partner Interests	A-74
ARTICLE XVI GENERAL PROVISIONS		A-75
Section 16.1	Addresses and Notices; Written Communications	A-75
Section 16.2	Further Action	A-76
Section 16.3	Binding Effect	A-76
Section 16.4	Integration	A-76
Section 16.5	Creditors	A-76
Section 16.6	Waiver	A-76
Section 16.7	Third-Party Beneficiaries	A-76
Section 16.8	Counterparts	A-77
Section 16.9	Applicable Law; Forum; Venue and Jurisdiction; Waiver of Trial by Jury	A-77
Section 16.10	Invalidity of Provisions	A-78
Section 16.11	Consent of Partners	A-78
Section 16.12	Facsimile Signatures	A-78


Dated:		American Midstream Partners, LP

Countersigned and Registered by:		By:	American Midstream GP, LLC, its General Partner

		By:


as Transfer Agent and Registrar
		Name:



By:		By:

	Authorized Signature		Secretary


Signature		Title	Date


/s/ Brian F. Bierbach Brian F. Bierbach		Chief Executive Officer and President (Principal Executive Officer) and Director	July 15, 2011

* Sandra M. Flower		Vice President of Finance (Principal Financial Officer and Principal Accounting Officer)	July 15, 2011

* Robert B. Hellman		Director	July 15, 2011

* Matthew P. Carbone		Director	July 15, 2011

* Edward O. Diffendal		Director	July 15, 2011

* L. Kent Moore		Director	July 15, 2011

* David L. Page		Director	July 15, 2011

* Gerald A. Tywoniuk		Director	July 15, 2011

*By:	/s/ Brian F. Bierbach Brian F. Bierbach Attorney-in-Fact