American Midstream Partners, LP - FORM 8-K - EX-99.1 - EXHIBIT 99.1

Attached files

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8-K - 8-K - American Midstream Partners, LP	form8-k111412.htm
EX-23.1 - EXHIBIT 23.1 - American Midstream Partners, LP	exhibit231111512.htm
EX-23.2 - EXHIBIT 23.2 - American Midstream Partners, LP	exhibit232111512.htm
EX-99.2 - EXHIBIT 99.2 - American Midstream Partners, LP	exhibit992proforma.htm

Exhibit 99.1

Item 1A. 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 our IPO offering document 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.

We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution of $0.4125 per unit. 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.

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 2011 ranged from a high of $4.85 per MMBtu to a low of $2.99 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 $2.32 per MMBtu in January 2012. 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 2011 ranged from a high of $113.93 per Bbl to a low of $75.67 per Bbl. Crude oil prices reached historically high levels in July 2008, hitting a peak of $145.29 per Bbl, and have demonstrated substantial volatility since then, with the forward month crude oil futures contracts ranging from $33.87 per Bbl in December 2008 to above $113.93 per Bbl in April 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 years ended December 31, 2011 and 2010, percent-of-proceeds arrangements accounted for approximately 41.3% and 34.6%, respectively, of our gross margin, or 58.8% and 53.7%, respectively, of the segment gross margin in our Gathering and Processing segment.

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 forgo 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 limited 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 limited experience in managing our business as a publicly traded partnership and has managed our business and assets for less than three 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.

We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (“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 requires 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 our initial public offering, we were a private company and were not 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 compared to larger, better capitalized companies. In our Gathering and Processing segment, Contango Operators Inc. and Venture Oil & Gas Co. accounted for approximately 18% and 21%, respectively, of our segment gross margin for the year ended December 31, 2011 and approximately 19% and 13%, respectively, of our segment gross margin for the year ended December 31, 2010. In our Transmission segment, Calpine Corporation accounted for approximately 37% and 38% of our segment gross margin for the years ended December 31, 2011 and 2010, respectively. 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 (US) L.P., (“EMUS”), and Dow Hydrocarbons and Resources, which accounted for approximately 55%, 16% and 9%, respectively, of our segment revenue for the year ended December 31, 2011 and approximately 34%, 29% and 10%, respectively, of our segment revenue for the year ended December 31, 2010. Additionally, EMUS, ExxonMobil and Calpine Corporation are the three largest purchasers of natural gas and transmission capacity, respectively, in our Transmission segment and accounted for approximately 22%, 57% and 8%, respectively, of our segment revenue for the year ended December 31, 2011 and approximately 31%, 43% and 10%, respectively, of our segment revenue for the year ended December 31, 2010.

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 (“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.

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 $0.1 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 gathered the most significant volumes of gas on this system and delivered 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 (“FERC”), under the Natural Gas Act of 1938 (“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 (“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 (“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 (“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 (“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 (“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 (“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 (“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 (“ESA”); and


•	the Toxic Substances Control Act (“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 (“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. For example, with respect to our Bazor Ridge processing plant, we 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 (“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 (“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. Please read “Business — Environmental Matters — Air Emissions” for more information about these matters. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.

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.

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 cleanup 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, which 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 (“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 the 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, the 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.

In July 2011, the EPA proposed rules that would establish new air emission controls for natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with natural gas processing activities. The proposed rules would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish

new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them during the first quarter of 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new leak detection and related equipment.

Several of the 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 (“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 (“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 (“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 (“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.

On August 1, 2011, we entered into a new credit facility. Our new credit facility limits 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 contains covenants requiring us to maintain certain financial ratios.

The provisions of our credit facility 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 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.

Our credit facility includes financial covenants and ratios. We may have difficulty maintaining compliance with the financial covenants, which include a maximum leverage ratio of 4.50 on a quarterly basis, which could adversely affect our operations and our ability to pay distributions to our unitholders.

We depend on our credit facility for future capital needs and to fund a portion of cash distributions to unitholders, as necessary. We are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the covenants under our credit facility could result in a default, which could cause all of our existing indebtedness to become immediately due and payable.

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 affect 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.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations sectors, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cyber-attacks on our customer and employee data may result in financial loss and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

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.

AIM Midstream Holdings owns and controls our general partner and appoints all of the officers and directors of our general partner, some of whom are also 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 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; and

•

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.

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.

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

We are approved to list our common units on the NYSE. Because we are 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.

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.

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

Our general partner intends to continue limiting 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 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 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.

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

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

•

provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;


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

•

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


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


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


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


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


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

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

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

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

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

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

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

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

The unitholders currently are unable to remove our general partner without its consent because our general partner and its affiliates owns sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding limited partner units voting together as a single class is required to remove our general partner AIM Midstream Holdings who owns 57.8% 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.

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.

AIM Midstream Holdings currently holds 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. AIM Midstream Holdings owns 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.

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.

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

Tax Risks to Common Unitholders

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 (“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 resulting 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 have adopted.

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.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and the related notes thereto included elsewhere in this Form 10-K. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under the caption “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are a growth-oriented Delaware limited partnership that was formed by affiliates of 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 five intrastate pipelines. We also own a 50% undivided, non-operating interest in a processing plant located in southern Louisiana. Our primary assets, which are strategically located in Alabama, Louisiana, Mississippi, 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.

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 (“NGLs”) under percent-of-proceeds (“POP”) arrangements. We own and operate three processing facilities that collectively produced an average of approximately 52.6Mgal/d and 34.1 Mgal/d of gross NGLs for years ended December 31, 2011 and 2010, respectively. Effective November 1, 2011, we acquired a 50% undivided non-operating interest in the Burns Point Plant from which we received 11.3 Mgal/d of NGLs to our account. In addition, in connection with our elective processing arrangements, we contract for processing capacity at the Toca plant operated by a subsidiary Enterprise, where we have the option to process natural gas that we purchase. Under these arrangements, we sold an average of approximately 27.4 Mgal/d and 28.1 Mgal/d of net equity NGL volumes for the years ended December 31, 2011 and 2010, respectively.

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. Under our POP processing contract with Enterprise, we can process raw natural gas through the Toca plant, whether for our customers or our own account. 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.

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.

Significant Developments During the Year Ended December 31, 2011

Initial Public Offering

On July 26, 2011, we commenced the initial public offering of our common units pursuant to our Registration Statement on Form S-1, Commission File No. 333-173191 (the “Registration Statement”), which was declared effective by the SEC on July 26, 2011. Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner, & Smith Incorporated acted as representatives of the underwriters and as joint book-running managers of the offering.

Upon closing of our IPO on August 1, 2011, we issued 3,750,000 common units pursuant to the Registration Statement at a price per unit of $21.00. The Registration Statement registered the offer and sale of securities with a maximum aggregate offering price of $90,562,500. The aggregate offering amount of the securities sold pursuant to the Registration Statement was $78,750,000. In our IPO, we granted the underwriters a 30 day option to purchase up to 562,500 additional units to cover over-allotments, if any, on the same terms. This option expired unexercised on August 30, 2011.

After deducting underwriting discounts and commissions of $4.9 million paid to the underwriters, offering expenses of $4.2 million and a structuring fee of $0.6 million, the net proceeds from our IPO were $69.1 million. We used all of the net offering

proceeds from our IPO for the uses described in the final prospectus filed with the SEC pursuant to Rule 424(b) on July 27, 2011. These uses included the following:


•	repayment in full of the outstanding balance under our $85 million credit facility of $58.6 million;


•	termination, in exchange for a payment of $2.5 million, of the advisory services agreement between our subsidiary, American Midstream, LLC, and affiliates of American Infrastructure MLP Fund, L.P.;


•	establishment of 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


•	the making of an aggregate distribution of $5.8 million, on a pro rata basis, to AIM Midstream Holdings, participants in our long-term incentive plan holding common units and the General Partner. The distribution to AIM Midstream Holdings and the General Partner was a reimbursement for certain capital expenditures incurred with respect to assets contributed to us.

On July 29, 2011, in connection with the closing of our initial public offering, our general partner contributed 76,019 of our common units to us in exchange for 76,019 general partner units in order to maintain its 2.0% general partnership interest in us. This transaction was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.

New $100 Million Credit Facility

In connection with our IPO, we paid off the amounts outstanding under our $85 million credit facility (“old credit facility”) evidenced by our credit agreement with a syndicate of lenders, for which Comerica Bank acted as Administrative Agent, and entered into a $100 Million Credit Facility evidenced by a credit agreement with 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”). The new credit facility also provides for a $50 million dollar accordion feature for accretive growth projects. If the accordion feature were to be exercised, the total commitment under the new facility would be $150 million.

We utilized a portion of the draws from our new credit facility to (i) make an aggregate distribution of $27.9 million, on a pro rata basis to AIM Midstream Holdings, to participants in our LTIP holding common units and our general partner and (ii) pay fees and expenses of $2.3 million relating to our new credit facility. The distribution made to AIM Midstream Holdings and our general partner was a reimbursement for certain capital expenditures incurred with respect to assets previously contributed to us.

Acquisition of a 50% non-operating interest in the Burns Point Plant

On December 1, 2011, we acquired a 50% undivided interest in the Burns Point Plant from Marathon Oil Company for total cash consideration of $35.5 million. No liabilities of the Seller were assumed. The purchase was effective November 1, 2011. The remaining 50% undivided interest is owned by the Plant operator, Enterprise Gas Processing, LLC (“Operator”). The Plant, which is an unincorporated venture, is governed by a construction and operating agreement.

The Burns Point Plant is located in St. Mary Parish, Louisiana, and processes raw natural gas using a cryogenic expander. The Plant inlet volumes are sourced from offshore natural gas production via our Quivira system, Gulf South pipelines and onshore from individual producers near the plant. Our Quivira system currently supplies approximately 85% of the inlet volume to the plant. The residue gas is transported, via pipeline to Gulf South and Tennessee Gas Pipeline and the Y-grade liquid is transported via pipeline to K/D/S Promix, LLC (“Promix”), an Enterprise operated fractionator. The current operating capacity of the plant is 165 MMcf/d. The acquisition complemented our existing assets given the location of the Plant in comparison to the Quivira system.

Subsequent Event

On January 24, 2012, we announced a distribution of $0.435 per unit for the fourth quarter 2011, payable on February 10, 2012 to unit holders of record on February 3, 2012.

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 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 (“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. However, we also have contracts under which we retain a percentage of the resulting NGLs and do not retain a percentage of residue natural gas, such as for our interest in the Burns Point Plant. Please read “Business — Gathering and Processing Segment — Gloria System.”


•	Interest in the Burns Point Plant

We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations, our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.

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 years ended December 31, 2011 and 2010:



	For the Year Ended December 31, 2011				For the Years Ended December 31, 2010
	Segment Gross Margin		Percent of Segment Gross Margin		Segment Gross Margin		Percent of Segment Gross Margin
	(in millions)				(in millions)
Gathering and Processing
Fee based	$	9.3	28.6	%	$	6.5	26.4	%
Fixed Margin	4.1		12.6	%	4.9		19.9	%
Percent-of-Proceeds	19.1		58.8	%	13.2		53.7	%
Total	$	32.5	100.0	%	$	24.6	100.0	%
Transmission
Firm transportation	$	10.4	75.9	%	$	10.8	80.0	%
Interruptible transportation	2.1		15.3	%	2.0		14.8	%
Fixed margin	1.2		8.8	%	0.7		5.2	%
Total	$	13.7	100.0	%	$	13.5	100.0	%

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 work-overs 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 Transmission 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 metrics that we use to evaluate our performance. 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 mark-to-market adjustments related to our commodity derivatives. For the year ended December 31, 2011, $0.5 million of unrealized losses was excluded from gross margin and the Gathering and Processing segment gross margin.

Effective April 1, 2011, we changed our gross margin and segment gross margin measure to exclude realized gains and losses associated with the early termination of commodity derivative contracts. For the year ended December 31, 2011, $3.0 million in such realized losses was excluded from gross margin and 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 without sacrificing safety or the environment. 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

Adjusted EBITDA is a measure used 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 unit holders 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.

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, amortization of commodity put purchase costs, and selected gains that are unusual or non-recurring. The GAAP measure most directly comparable to adjusted EBITDA is net income.

We changed our calculation of adjusted EBITDA for 2011 to include the straight-line amortization of commodity put premiums over the life of the associated commodity put contracts. This is necessary as all unrealized commodity gains and losses, by definition, are excluded in calculating adjusted EBITDA and such premium costs would only be included in the calculation of adjusted EBITDA at the expiration of the put contract. We believe this treatment better reflects the allocation of commodity put premium costs over the benefit period of the commodity put contract. Commodity put premium amortization included in the calculation of adjusted EBITDA $0.4 million for the year ended December 31, 2011. Further we made a change to the calculation to exclude construction, operating and maintenance agreement (“COMA”) income from adjusted EBITDA. COMA income excluded from adjusted EBITDA for the year ended December 31, 2011 was $0.9 million.

Distributable Cash Flow

Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder). Distributable cash flow will not reflect changes in working capital balances.

We define distributable cash flow as adjusted EBITDA plus interest income, less cash paid for interest expense, normalized integrity management costs and normalized maintenance capital expenditures. The GAAP measure most directly comparable to distributable cash flow is net cash flows from operating activities.

Note About Non-GAAP Financial Measures

Gross margin, adjusted EBITDA and distributable cash flows are all non-GAAP financial measures. Each has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

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.

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 included in this Form 10-K.

The following tables reconcile the non-GAAP financial measures, adjusted EBITDA and distributable cash flow used by management to their most directly comparable GAAP measures:



										Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009			Ten Months ended October 31, 2009
	2011			2010						Ten Months ended October 31, 2009
	(in thousands)
Reconciliation of Adjusted EBITDA to Net Income (Loss)
Net income	$	(11,698	)	$	(8,644	)	$	(6,992	)	$	(5,337	)
Add:
Depreciation expense	20,705			20,013			2,978			12,630
Interest expense	4,508			5,406			910			3,728
Realized loss on early termination of commodity derivatives	2,998			—			—			—
Realized loss on commodity put purchase costs	308			—			—			—
Unrealized (gain) loss on commodity derivatives	541			—			—			—
Non-cash equity compensation expense	1,607			1,185			150			—
Advisory services agreement termination fee	2,500			—			—			—
Special distribution to holders of LTIP phantom units	1,624			—			—			—
Transaction costs	282			303			6,404			—
Deduct:
Construction, operating and maintenance agreement income “(COMA”)	879			—			—			—
Straight-line amortization of put costs (1)	409			—			—			—
Other post retirement plan net periodic benefit (cost)	82			—			—			—
Gain (loss) on acquisition of assets, net	565			—			—			—
Gain (loss) on sale of assets, net	399			—			—			—
Adjusted EBITDA	$	21,041		$	18,263		$	3,450		$	11,021


(1)	Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract.



	For the Year Ended December 31,			Period from August 20, 2009 (Inception Date) to December 31, 2009
	2011	2010
	(in thousands)
Reconciliation of Distributable Cash to Net Cash Flows from Operating Activities:
Net cash provided / (used) in operating activities	10,432	13,791		(6,531	)
Add:
Change in operating assets and liabilities	1,247	(45	)	2,790
Interest expense	3,246	4,591		792
Advisory services agreement termination fee	2,500	—		—
Realized (gain) loss on early termination of commodity derivatives	2,998	—		—
Special distribution to holders of LTIP phantom units	1,624	—		—
Transaction costs	282	303		6,404
Deduct:
Cash interest expense (1)	3,246	4,591		792
Straight-line amortization of put costs (2)	409	—		—
COMA income	879	—		—
Integrity management costs (3)	1,500	1,500		250
Maintenance capital expenditures (4)	3,083	3,000		500
Distributable Cash Flow	13,212	9,549		1,913


(1)	Excludes amortization of debt issuance costs and mark-to-market adjustments related to interest rate derivatives.


(2)	Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract.


(3)	Amounts noted represent average estimated integrity management costs over the 7 year mandatory testing cycle.


(4)	Amounts noted represent estimated annual maintenance capital expenditures of $3.5 million which is what we expect to be required to maintain our assets over the long term.

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 information of our Predecessor:

•

is 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


•	reflects 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.


•	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.


•	After our initial public offering, we began incurring 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 our IPO, we paid $2.5 million to those affiliates and terminated 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 November 2010, we completed the construction of the Winchester lateral into our Bazor Ridge processing plant. Since its completion, the lateral has provided approximately 4,000 MMcf/d of incremental gas into the Bazor Ridge plant.


•	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.


•	On December 1, 2011, we acquired a 50% undivided interest in the Burns Point Plant from Marathon Oil Company for total cash consideration of $35.5 million. No liabilities of the Seller were assumed. The purchase was effective November 1, 2011.

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 2012 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 24.4 trillion cubic feet, or Tcf, in 2011, compared to approximately 24.1 Tcf in 2010, representing an increase of approximately 1.2%. Domestic production of natural gas grew from approximately 22.6 Tcf in 2010 to approximately 24.4 Tcf in 2011, or an 8.0% increase. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States, representing approximately 59.0% of the total natural gas consumed in the United States during 2011. 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 5.7 million barrels per day, or MMBbl/d, in 2011, compared to approximately 5.5 MMBbl/d in 2010, representing an increase of approximately 3.6%. 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.

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.

Results of Operations — Combined Overview

Our distributable cash flow for the year ended December 31, 2011 was $13.2 million. Operating results for the year ended December 31, 2011 showed significant increases over operating results for the year ended December 31, 2010. For the year ended December 31, 2011, gross margin increased 21.2% from that of 2010. This positive performance was tempered, in part, by an unusual set of operational issues, both ours and third party’s that reduced gathering and processing volumes which in turn impacted our financial performance in the third quarter 2011.

For the Gloria and Lafitte systems, a work-over on the largest well supplying the Gloria system, a delay in connecting a well planned for the second quarter and compression challenges combined to reduce volumes into the TOCA processing plant. These issues have been largely addressed and volumes have returned to expected levels.

For the Quivira system, the Burns Point plant experienced compression challenges associated with unusually hot temperatures and the increased volumes our Quivira system brought to the plant, which reduced volumes and revenues on Quivira during the third quarter. We are working with Enterprise, the operator of the Burns Point plant, to proactively address this dynamic before next summer, which we believe is achievable. Quivira is again operating as expected.

The following table and discussion presents certain of our historical consolidated financial data for the periods indicated. The results of operations by segment are discussed in further detail following this combined overview.



										Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009			Ten Months ended October 31, 2009
	2011			2010						Ten Months ended October 31, 2009
	(in thousands)
Statement of Operations Data:
Revenue	$	248,282		$	212,248		$	32,833		$	143,132
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—			—			—
Unrealized gain (loss) on commodity derivatives	(541		)	(308		)	—			—
Total revenue	244,743			211,940			32,833			143,132
Operating expenses
Purchases of natural gas, NGLs and condensate	202,403			173,821			26,593			113,227
Direct operating expenses	12,856			12,187			1,594			10,331
Selling, general and administrative expenses	10,794			7,120			1,196			8,553
Advisory services agreement termination fee	2,500			—			—			—
Transaction expenses	282			303			6,404			—
Equity compensation expense (a)	3,357			1,734			150			—
Depreciation expense	20,705			20,013			2,978			12,630
Total operating expenses	252,897			215,178			38,915			144,741
Gain (loss) on acquisition of assets	565			—			—			—
Gain (loss) on sale of assets, net	399			—			—			—
Operating income (loss)	(7,190		)	(3,238		)	(6,082		)	(1,609		)
Interest (expense)	(4,508		)	(5,406		)	(910		)	(3,728		)
Net income (loss)	$	(11,698	)	$	(8,644	)	$	(6,992	)	$	(5,337	)
Other Financial Data:
Gross margin (b)	$	46,187		$	38,119		$	6,240		$	29,905
Adjusted EBITDA (c)	$	21,041		$	18,263		$	3,450		$	11,021
Distributable cash flow (d)	$	13,212		$	9,549		$	1,913


(a)	Represents cash and non-cash costs related to our LTIP. Of these amounts, $1.6 million, $1.2 million and $0.2 million, for the years ended December 31, 2011 and 2010 and the period ended December 31, 2009, respectively, were non-cash expenses.

(b)

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 18 to our audited consolidated financial statements included in this Annual Report beginning on page F-1 for a discussion of how we use gross margin to evaluate our operating performance, please read “— How We Evaluate Our Operations”.


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


(d)	For a definition of distributable cash flow and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use distributable cash flow to evaluate our operating performance, please read “—How We Evaluate Our Operations”.

Year ended December 31, 2011 compared to year ended December 31, 2010

Revenue. Our total revenue for the year ended December 31, 2011 was $244.7 million compared to $211.9 million for the year ended December 31, 2010. This increase of $32.8 million was primarily due to higher NGL sales volumes from owned processing facilities, higher realized NGL prices and natural gas sales volumes in our Gathering and Processing segment and higher natural gas sales gas sales volumes in our Transmission segment. This increase in revenue was also a result of a $0.5 million increase in COMA income. This increase was partially offset by lower realized natural gas prices in our Gathering and Processing segment and one-time $3.0 million charge resulting from the unwind and reset of our commodity hedge contracts in June 2011.

Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the year ended December 31, 2011 were $202.4 million compared to $173.8 million in the year ended December 31, 2010. This increase of $28.6 million was primarily due to higher NGL sales volumes and NGL prices related to owned processing plants’ POP contracts and higher natural gas purchase volumes in our Gathering and Processing and Transmission segments. This increase was partially offset by lower natural gas purchase costs in our Gathering and Processing segment.

Gross Margin. Gross margin for the year ended December 31, 2011 was $46.2 million compared to $38.1 million for the year ended December 31, 2010. This increase of $8.1 million was primarily due to higher throughput volume and associated NGL production from owned processing plants, improved processing and POP margins from higher NGL and condensate prices and higher throughput in our Gathering and Processing segment. We also achieved incremental gross margin of $1.1 million associated with our acquisition of a 50% undivided, non-operating, interest in the Burns Point Plant effective November 1, 2011. In addition this increase was also attributable to a $0.5 million increase in COMA income.

Direct Operating Expenses. Direct operating expenses in the year ended December 31, 2011 were $12.8 million compared to $12.2 million in the year ended December 31, 2010. This increase of $0.6 million was primarily due to: (i) $0.2 million incremental costs related to service fees and costs to address operational matters; (ii) $0.3 million of added expenses associated with our 50% interest in the operating costs incurred at the Burns Point Plant; and (iii) $0.4 million of line losses in our Transmission segment. The operational cost increases were partially offset by a reduction in personnel related costs.

Selling, General and Administrative Expenses. SG&A expenses for the year ended December 31, 2011 were $10.8 million compared to $7.1 million for the year ended December 31, 2011. This increase of $3.7 million was primarily due to: (i) $1.9 million of incremental personnel costs and related benefits necessary to operate and grow a public company; (ii) $0.2 million in additional expenses associated with maintaining operational locations and services; (iii) $1.0 million of added costs associated with our IPO process and continued compliance and requirements for a publicly traded company; and (iv) $0.3 million of incremental costs associated with outside services and contract labor to assist in maintaining and maximizing operational efficiency of our systems.

Advisory Services Agreement Termination Fee. In connection with our IPO in August 2011, we terminated the advisory services agreement with our sponsor in exchange for a payment of $2.5 million.

Equity Compensation Expense. Compensation expense related our LTIP for the year ended December 31, 2011 was $3.4 million compared to $1.7 million for the year ended December 31, 2010. This increase of $1.7 million was primarily due to buy-out of distribution equivalent rights (“DER’s”) associated with unvested phantom units at a cost of $1.5 million, a payment to holders of unvested phantom units without DER’s of $0.1 million, increased amortization of $0.1 million associated with March 2011 phantom unit grants, off-set in part by the lack of DER payments in the second half of 2011 and a modification in amounts amortized due to the elimination of the DER’s.

Depreciation Expense. Depreciation expense in the year ended December 31, 2011 was $20.7 million compared to $20.0 million for the year ended December 31, 2010. This increase of $0.7 million was due to depreciation associated with capital projects placed into service during the period.

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 $173.9 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 $7.1 million, compared to $1.2 million and $8.6 million in the 2009 Successor Period and the 2009 Predecessor Period, respectively. 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.

Equity Compensation Expense. Compensation expense related our LTIP for the year ended December 31, 2010 was $1.7 million and $0.2 million in the 2009 Successor Period, respectively. Because we adopted the LTIP in November 2009, there were no LTIP expenses in the 2009 Predecessor Period.

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.

Results of Operations — Segment Results

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



									Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009		Ten Months ended October 31, 2009
	2011			2010					Ten Months ended October 31, 2009
	(in thousands except operational data)
Segment Financial and Operating Data:
Gathering and Processing segment
Financial data:
Revenue	$	181,517		$	158,763		$	27,857	$	132,957
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—			—		—
Unrealized gain (loss) on commodity derivatives	(541		)	(308		)	—		—
Total revenue	177,978			158,455			27,857		132,957
Purchases of natural gas, NGLs and condensate	$	149,374		$	133,860		$	24,159	$	112,933
Direct operating expenses	$	7,636		$	7,721		$	956	$	7,134
Other financial data:
Segment gross margin	$	32,450		$	24,595		$	3,698	$	20,024
Operating data:
Average throughput (MMcf/d)	250.9			175.6			169.7		211.8
Average plant inlet volume (MMcf/d) (a)	36.7			9.9			11.4		11.7
Average gross NGL production (Mgal/d) (a)	54.5			34.1			38.2		39.3
Average realized prices:
Natural gas ($/MMcf)	$	4.09		$	4.61		$	4.71	$	3.76
NGLs ($/gal)	$	1.32		$	1.08		$	1.05	$	0.70
Condensate ($/gal)	$	2.41		$	1.82		$	1.68	$	1.16
Transmission segment
Financial data:
Total revenue	$	66,765		$	53,485		$	4,976	$	10,175
Purchases of natural gas, NGLs and condensate	$	53,029		$	39,961		$	2,434	$	294
Direct operating expenses	$	5,220		$	4,466		$	638	$	3,197
Other financial data:
Segment gross margin	$	13,737		$	13,524		$	2,542	$	9,881
Operating data:
Average throughput (MMcf/d)	381.1			350.2			381.3		357.6
Average firm transportation - capacity reservation (MMcf/d)	702.2			677.6			701.0		613.2
Average interruptible transportation - throughput (MMcf/d)	69.0			80.9			118.0		121.0


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

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Gathering and Processing Segment

Revenue. Segment revenue for the year ended December 31, 2011 was $177.9 million compared to $158.5 million for the year ended December 31, 2010. This increase of $19.4 million was, in part, due to higher throughput and associated increased NGL sales volumes at our Bazor Ridge plant due to the completion of our Winchester laterial in the fourth quarter of 2010 and the production from several new wells drilled on the system in 2011. Revenue in our Gathering and Processing segment also increased as a result of higher realized NGL and condensate prices which increased revenues at our owned processing plants and the volumes associated with our elective processing agreements. Revenues also increased as a result of higher natural gas sales volumes, primarily the increased demand at the Conoco Alliance refinery, which we serve with production from our Lafitte system and our interconnect with the Tennessee Gas Pipeline. This increase was partially offset by lower realized natural gas prices.

•

Total natural gas throughput volumes on our Gathering and Processing segment were 250.9 MMcf/d during the year ended December 31, 2011 compared to 175.6 MMcf/d during the year ended December 31, 2010. Natural gas inlet volumes at our owned processing plants were 36.7 MMcf/d during the year ended December 31, 2011 compared to 9.9 MMcf/d for the year ended December 31, 2010. Gross NGL production volumes from our owned processing plants were 54.5M gal/d during the year ended December 31, 2011 compared to 34.1 Mgal/d during the year ended December 31, 2010. Primary factors influencing these gains were:


•	The connection of additional Contango production on our Quivira system in the third quarter 2010 representing a 43% increase year over year;


•	new incremental throughput volume from the Burns Point Plant from the 50% interest we acquired effective November 1, 2011;


•	an increase in volume across our Lafitte and Gloria systems as a result of higher natural gas demand at the Conoco Alliance refinery and incremental volume sourced from our interconnect with Tennessee Gas Pipeline, which combined to increase volumes across the systems by 28% per year; and


•	the completion of the Winchester lateral on our Bazor Ridge system in the fourth quarter 2010, combined with the connection of the two new wells in the first and second quarter 2011, which contributed to a 46% increase year over year.

•

The average realized price of natural gas for the year ended December 31, 2011 was $4.09/Mcf, compared to $4.61 /Mcf for the year ended December 31, 2010. The average realized price of NGLs for the year ended December 31, 2011 was $1.32/gal, compared to $1.08/gal for the year ended December 31, 2010. The average realized price of condensate for the year ended December 31, 2011 was $2.41/gal, compared to $1.82/gal for the year ended December 31, 2010.

We entered into a series of swap and put contracts in January 2011 and swap contracts again in June 2011. These commodity derivative transactions had a negative net effect of $0.8 million on our revenue related to unrealized losses for the year ended December 31, 2011. In June 2010, we purchased put contracts that extended through June 2011. For the year ended December 31, 2010 we recognized an unrealized valuation loss of $0.3 million related to this contract.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the year ended December 31, 2011 were $149.4 million compared to $133.9 million for the year ended December 31, 2010. This increase of $15.5 million was primarily due to higher NGL sales volumes and NGL prices related to owned processing plants’ POP contracts and higher natural gas purchase volumes to provide natural gas for the Conoco Alliance refinery. This increase was partially offset by lower natural gas prices.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2011 was $32.5 million compared to $24.6 million for the year ended December 31, 2010. This increase of $7.9 million was primarily due to higher throughput volume and associated NGL production at our Bazor Ridge processing plant, increased throughput volume on our Quivira system, higher realized NGL prices which positively impacted margins associated with our POP and elective processing agreements, and the acquisition of our 50% interest in the Burns Point Plant in November 2011. In addition, a $0.3 million unrealized loss on commodity derivatives was recognized in 2010. Beginning January 1, 2011, such unrealized losses are excluded from segment gross margin. Gathering and Processing segment represented 70.3% of our total gross margin for the year ended December 31, 2011, compared to 64.5% for the year ended December 31, 2010.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2011 were $7.6 million compared to $7.7 million for the year ended December 31, 2010.

Transmission Segment

Revenue. Segment revenue for the year ended December 31, 2011 was $66.8 million compared to $53.5 million for the year ended December 31, 2010. Total natural gas throughput on our Transmission systems for the year ended December 31, 2011 was 381.1MMcf/d compared to 350.2 MMcf/d in the year ended December 31, 2010. This increase of $13.3 million in revenue was primarily due to a full year’s impact of our fixed margin agreement which began in the second quarter 2010 to supply gas to Exxon on our MLGT system offset in part by lower volumes and natural gas prices associated with an affiliate fixed margin agreement on the Midla system. Our commodity derivatives had no effect on segment revenue for the years ended December 31, 2011 and 2010.

Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the year ended December 31, 2011 were $53.0 million compared to $40.0 million for the year ended December 31, 2010. This increase of $13.0 million was primarily due to a full year’s impact of our fixed margin agreement began in the second quarter 2010 to supply gas to Exxon on our MLGT system offset in part by lower volumes and natural gas prices associated with an affiliate fixed margin agreement on the Midla system.

Segment Gross Margin. Segment gross margin for the year ended December 31, 2011 was $13.7 million compared to $13.5 million for the year ended December 31, 2010. Segment gross margin for the Transmission segment represented 29.7% of our total gross margin for year ended December 31, 2011, compared to 35.5% for the year ended December 31, 2010.

Direct Operating Expenses. Direct operating expenses for the year ended December 31, 2011 were $5.2 million compared to $4.5 million for the year ended December 31, 2010. This increase of $0.7 million was primarily due to $0.2 million incremental costs related to service fees and costs to address operational matters and a $0.5 million increase in line losses.

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.

Liquidity and Capital Resources

Our business is capital intensive and requires significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities.

The principal indicators of our liquidity at December 31, 2011 were our cash on hand and availability under our new credit facility as discussed below. As of December 31, 2011, our available liquidity was $28.2 million, comprised of cash on hand less $0.5 million and $27.8 million available under our new credit facility. As of February 29, 2012, our available liquidity was $26.3 million. In the near term, 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 the minimum quarterly distribution on all of our outstanding common and subordinated units, the corresponding distribution on our 2.0% general partner interest and meet our requirements for working capital and capital expenditures over the next 12 months.

Our credit facility also provides for a $50 million accordion feature for accretive growth projects. If the accordion feature were to be fully exercised and approved by our lenders, the total commitment under the new facility would be $150 million.

The principal indicators of our liquidity at September 30, 2012 were our cash on hand and availability under our credit facility as discussed below. As of September 30, 2012, we had cash on hand of $0.5 million and $118.7 million borrowed under our credit facility. As of September 30, 2012, our available liquidity was $5.4 million.

We are required to comply with certain financial covenants and ratios in our credit facility. As of September 30, 2012, our leverage ratio, one of the primary financial covenants that we are required to maintain under our credit facility was 4.31. Our credit facility requires that our leverage ratio not exceed 4.50. Our ability to comply with these covenants and ratios in the future will be affected by the levels of debt and of cash flow from our operations, among other factors.

In order to remain in compliance with our financial covenants and ratios under our credit facility, we believe that we have several options available to us that we may pursue separately or in combination. First, subject to market conditions, we have the ability to issue debt or equity securities to refinance or pay down outstanding borrowings under our credit facility and to fund future growth capital expenditures. Second, we may request a waiver from the lenders in our credit facility. Third, we may seek to reduce our debt by amounts that exceed our operating cash flows through actions such as a reduction in capital expenditures; suspension of our quarterly distributions to subordinated unitholders and, thereafter, unitholders; the sale of assets; further reduction of operating and administrative costs; or other steps to enhance liquidity and reduce debt and avoid default.

If we were not in compliance with the financial covenants in the credit facility, or if we did not enter into an agreement to refinance or extend the due date on the credit facility, our debt could become due and payable upon acceleration by the lenders in our banking group. In addition, failure to comply with any of the covenants under our credit facility could adversely affect our ability to fund ongoing operations and growth capital requirements as well as our ability to pay distributions to our unitholders.

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 requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. Our working capital was $2.7 million at December 31, 2011.

Cash Flows

The following table reflects cash flows for the applicable periods:



										Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009			Ten Months ended October 31, 2009
	2011			2010						Ten Months ended October 31, 2009
Net cash provided by (used in):
Operating activities	$	10,432		$	13,791		$	(6,531	)	$	14,589
Investing activities	(41,744		)	(10,268		)	(151,976		)	(853		)
Financing activities	32,120			(4,609		)	159,656			(14,008		)

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Operating Activities. Net cash provided by (used in) operating activities was $10.4 million for year ended December 31, 2011 compared to $13.8 million for the year ended December 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. In addition, $3.0 million was used to terminate our NGL swaps with two counterparties, purchase an NGL put for $0.7 million, $1.5 million was used to pay holders of phantom units under our LTIP in consideration for the elimination of the DER provision in existing LTIP agreements and $2.5 million was used to buy-out the management agreement with AIM.

Investing Activities. Net cash provided by (used in) investing activities was ($41.7) million for the year ended December 31, 2011 compared to ($10.3) million for the year ended December 31, 2010. Cash provided by (used in) investing activities for the year ended December 31, 2011 was primarily a result of the purchase of a 50% undivided non-operating interest in the Burns Point plant for $35.5 million, a meter relocation costing $2.3 million on our MLGT system, $1.4 million for pipeline relocation work on our Gloria and Chalmette systems associated with levee improvements and $0.2 million for a Gloria compressor overhaul.

Financing Activities. Net cash provided by (used in) financing activities was $32.1 million for the year ended December 31, 2011 compared to ($4.6) million for the year ended December 31, 2010. The change in cash provided by (used in) financing activities was primarily a result of $69.1 million in net proceeds from our IPO, a decrease in other unit holder contributions of ($12.0), the ($58.6) million pay down of our $85 million credit facility, an initial draw of $30.0 million from our new $100 Million Credit Facility, debt issuance costs of ($2.5) million, a $14.5 million increase in net borrowings of long-term debt and an increase of ($31.7) million in distributions made to our unitholders.

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 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.

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 and the acquisition and 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, 2011, our capital expenditures exclusive of our purchase of the 50% undivided interest in the Burns Point Plant totaled $6.4 million including expansion capital expenditures of $0.5 million, maintenance capital expenditures of $2.1 million and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a 3^rd party) of $3.8 million. Although we classified our capital expenditures as expansion and maintenance, 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.

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 $0.1 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.

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	—
2018	—
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” in our Prospectus for more information about these matters.

As a result of these exceedances, 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 are in communication with regulatory officials at both the MDEQ and the EPA regarding the Bazor Ridge plant reporting issue.

Distributions

We intend to pay a quarterly distributions though we do not have a legal obligation to make distributions except as provided in our partnership agreement.

Our post initial public offering distributions consisted of a pro-rated distribution in November 2011 for the period from August 2, 2011 through September 30, 2011 of $0.2690 per unit, or $2.5 million and a distribution in February 2012 for the fourth quarter 2011 of $0.4325 per unit or $4.0 million.

Our Credit Facility

On August 1, 2011, we terminated our old credit facility and entered into our $100 million revolving credit facility. This new facility also contains a $50 million accordion feature which could bring the total facility commitment to $150 million.

The credit facility provides for a maximum borrowing equal to the lesser of (i) $100 million or (ii) 4.50 times adjusted consolidated EBITDA. We may elect to have loans under the credit facility bear interest either at a Eurodollar-based rate plus a margin ranging from 2.25% to 3.50% depending on our total leverage ratio then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (a) the Federal Funds Rate plus 1/2 of 1%, (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate”, and (c) the Eurodollar Rate plus 1.00% plus a margin ranging from 1.25% to 2.50% depending on the total leverage ratio then in effect. We also pay a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan.

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, August 1, 2016.

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 4.50 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, 2011.

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 (US) L.P. and Dow Hydrocarbons and Resources and accounted for approximately 55%, 16% and 9%, respectively, of our segment revenue for the year ended December 31, 2011. Additionally, Enbridge Marketing US, ExxonMobil and Calpine Corporation are the two largest purchasers of natural gas and transmission capacity, respectively, in our Transmission segment and accounted for approximately 22%, 57% and 8%, respectively, of our segment revenue for the year ended December 31, 2011. 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, Venture Oil & Gas Co.,and Contango Operators Inc.accounted for approximately 21% and 18%, respectively, of our segment gross margin for the year ended December 31, 2011. In our Transmission segment, Calpine Corporation accounted for approximately 37% of our segment gross margin for the year ended December 31, 2011. 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, 2011:



	Total		Less Than 1 Year		1 - 3 Years		3 - 5 Years		More Than 5 Years
	(in thousands)
Long term debt	$	66,270	$	—	$	—	$	66,270	$	—
Operating leases and service contract	1,774		415		1,105		254		—
Asset retirement obligation (“ARO”)	8,093		—		—		8,093		—
Total	$	76,137	$	415	$	1,105	$	74,617	$	—

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 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 years ended December 31, 2011 and 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, 2011 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, 2011, we have recorded liabilities of $8.1 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 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.

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.

Interest in the Burns Point Plant. We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations, our value of plant revenues taken in-kind and plant expenses reimbursed to the operator.

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 December 2012 for our commodity hedges. We monitor and review hedging positions regularly.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRS. The ASU amends previously issued authoritative guidance and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the ASU clarifies the FASB’s intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. This guidance will not have an impact on the Company’s financial position or results of operations.

In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income. The ASU amends previously issued authoritative guidance and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. These amendments remove the option under current U.S. GAAP to present the components of other comprehensive income as part of the statements of changes in stockholder’s equity. The adoption of this guidance will not have an impact on the Company’s financial position or results of operations, but will require the Company to present the statements of comprehensive income separately from its statements of equity, as these statements are currently presented on a combined basis.

In December 2011, the FASB issued ASU No. 2011-11 Disclosures about Offsetting Assets and Liabilities. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company’s financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Company is currently evaluating the provisions of ASU 2011-11.

Item 8. Financial Statements and Supplementary Data

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, 2011 and 2010 and the related consolidated statements of operations, of changes in partners' capital and of cash flows for the years ended December 31, 2011 and 2010 and the period from August 20, 2009 (inception date) to December 31, 2009. These financial statements are the responsibility of the Partnership'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 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, 2011 and 2010 and the results of their operations and their cash flows for the years ended December 31, 2011 and 2010 and the period from August 20, 2009 (inception date) to December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 23 “Liquidity” to the consolidated financial statements, the ability of the Company to implement its current business plan is dependent upon the Company successfully completing the various financing transactions in order to remain in compliance with its debt covenants.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 19, 2012 except for Note 22 for which the date is as of October 18, 2012 and Note 23 for which the date is as of November 15, 2012

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 statement of operations of American Midstream Partners Predecessor (the “Predecessor), and the related combined statements of group equity and of cash flows for the ten-month period ended October 31, 2009. These financial statements are the responsibility of American Midstream Partners, LP. 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 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 combined financial statements referred to above present fairly, in all material respects, the results of operations of American Midstream Predecessor and their cash flows for 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 17 to the financial statements, the financial results contain significant transactions with related parties.

/s/ PricewaterhouseCoopers, LLP

Houston, Texas

March 30, 2011

American Midstream Partners, LP and Subsidiaries

Consolidated Balance Sheets

(In thousands except unit amounts)



	December 31,
	2011		2010
Assets
Current assets
Cash and cash equivalents	$	871	$	63
Accounts receivable	1,218		656
Unbilled revenue	19,745		22,194
Risk management assets	456		—
Other current assets	3,323		1,523
Total current assets	25,613		24,436
Property, plant and equipment, net	170,231		146,808
Other assets, net	3,707		1,985
Total assets	$	199,551	$	173,229
Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	837	$	980
Accrued gas purchases	14,715		18,706
Current portion of long-term debt	—		6,000
Other loans	—		615
Risk management liabilities	635		—
Accrued expenses and other current liabilities	7,086		2,676
Total current liabilities	23,273		28,977
Other liabilities	8,612		8,078
Long-term debt	66,270		50,370
Total liabilities	98,155		87,425
Commitments and contingencies (see Note 16)
Partners’ capital
General partner interest (0.2 and 0.1 million units issued and outstanding as of December 31, 2011 and 2010, respectively)	1,091		2,124
Limited partner interest (9.1 and 5.4 million units issued and outstanding as of December 31, 2011 and 2010, respectively)	99,890		83,624
Accumulated other comprehensive income	415		56
Total partners’ capital	101,396		85,804
Total liabilities and partners’ capital	$	199,551	$	173,229

The accompanying notes are an integral part of these consolidated financial statements.

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Operations

(In thousands, except per unit amounts)



										Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009			Ten Months ended October 31, 2009
	2011			2010						Ten Months ended October 31, 2009
Revenue	$	248,282		$	212,248		$	32,833		$	143,132
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—			—			—
Unrealized gain (loss) on commodity derivatives	(541		)	(308		)	—			—
Total revenue	244,743			211,940			32,833			143,132
Operating expenses:
Purchases of natural gas, NGLs and condensate	202,403			173,821			26,593			113,227
Direct operating expenses	12,856			12,187			1,594			10,331
Selling, general and administrative expenses	10,794			7,120			1,196			8,553
Advisory services agreement termination fee (See Note 17)	2,500			—			—			—
Transaction expenses (See Note 2)	282			303			6,404			—
Equity compensation expense (See Note 14)	3,357			1,734			150			—
Depreciation and accretion expense	20,705			20,013			2,978			12,630
Total operating expenses	252,897			215,178			38,915			144,741
Gain (loss) on acquisition of assets	565			—			—			—
Gain (loss) on sale of assets, net	399			—			—			—
Operating income (loss)	(7,190		)	(3,238		)	(6,082		)	(1,609		)
Other income (expenses):
Interest expense	(4,508		)	(5,406		)	(910		)	(3,728		)
Net income (loss)	$	(11,698	)	$	(8,644	)	$	(6,992	)	$	(5,337	)
General partner’s interest in net income (loss)	(233		)	(173		)	(140		)
Limited partners’ interest in net income (loss)	$	(11,465	)	$	(8,471	)	$	(6,852	)
Limited partners’ net income (loss) per unit (See Note 19)	$	(1.64	)	$	(1.66	)	$	(3.13	)
Weighted average number of units used in computation of limited partners’ net income (loss) per unit	6,997			5,099			2,187

The accompanying notes are an integral part of these consolidated financial statements.

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Changes in Partners’ Capital

(In thousands)



	Limited Partner Common Units		Limited Partner Subordinated Units	Group Equity			Limited Partner Interest			General Partner Units	General Partner Interest			Accumulated Other Comprehensive Income		Total
Predecessor:
Balance at December 31, 2008	—		—	$	151,799		—			—	—			—		$	151,799
Net income (loss)	—		—	(5,337		)	—			—	—			—		(5,337		)
Contributions by parent	—		—	111,103			—			—	—			—		111,103
Distributions to parent	—		—	(25,772		)	—			—	—			—		(25,772		)
Other comprehensive loss	—		—	(201		)	—			—	—			—		(201		)
Balance at October 31, 2009	—		—	$	231,592		$	—		—	$	—		$	—	$	231,592
Successor:
Balances at August 20, 2009 (Inception date)	—		—	—			$	—		—	$	—		$	—	$	—
Net income (loss)	—		—	—			(6,852		)	—	(140		)	—		(6,992		)
Unitholder contributions	4,756		—	—			98,000			97	2,000			—		100,000
Unitholder distributions	—		—	—			—			—				—		—
Unit based compensation	—		—	—			—			—	150			—		150
Adjustments to other post retirement plan assets and liabilities	—		—	—			—			—				46		46
Balances at December 31, 2009	4,756		—	—			91,148			97	2,010			46		93,204
Net income (loss)	—		—	—			(8,471		)	—	(173		)	—		(8,644		)
Unitholder contributions	571		—	—			11,760			12	240			—		12,000
Unitholder distributions	—		—	—			(11,545		)	—	(234		)	—		(11,779		)
LTIP vesting	44		—	—			903			—	(903		)			—
Tax netting repurchase	(8	)		—			(171		)	—	—			—		(171		)
Unit based compensation	—		—	—			—			—	1,184			—		1,184
Adjustments to other post retirement plan assets and liabilities			—	—										10		10
Balances at December 31, 2010	5,363		—				83,624			109	2,124			56		85,804
Net income (loss)							(11,465		)		(233		)	—		(11,698		)
Recapitalization	(4,602	)	4,526	—			—			76	—			—		—
Issuance of common units to public, net of offering costs	3,750		—	—			69,085			—	—			—		69,085
Unitholder distributions	—		—	—			(42,682		)	—	(864		)	—		(43,546		)
LTIP vesting	62		—	—			1,286			—	(1,286		)	—		—
Tax netting repurchase	(12	)	—	—			(215		)	—	—			—		(215		)
Unit based compensation	—		—	—			257			—	1,350			—		1,607
Adjustments to other post retirement plan assets and liabilities	—		—	—			—			—	—			359		359
Balances at December 31, 2011	4,561		4,526	$	—		$	99,890		185	$	1,091		$	415	$	101,396

The accompanying notes are an integral part of these condensed consolidated financial statements.

American Midstream Partners, LP and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)



										Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009			Ten Months ended October 31, 2009
	2011			2010
Cash flows from operating activities
Net income (loss)	$	(11,698	)	$	(8,644	)	$	(6,992	)	$	(5,337	)
Adjustments to reconcile net income (loss) to net cash provided (used) in from operating activities:
Depreciation and accretion expense	20,705			20,013			2,978			12,630
Amortization of deferred financing costs	1,262			807			118			—
Mark-to-market on derivatives	849			385			5			—
Unit based compensation	1,607			1,185			150			—
OPEB plan net periodic (benefit) cost	(82		)	—			—			—
(Gain) loss on acquisition of assets	(565		)	—			—			—
(Gain) loss on sale of assets	(399		)	—			—			—
Changes in operating assets and liabilities:
Accounts receivable	(562		)	791			(1,447		)	1,163
Unbilled revenue	2,449			(3,865		)	(18,329		)	(387		)
Due from affiliates	—			—			—			(13,144		)
Notes receivable from affiliates	—			—			—			26,872
Risk management assets	(670		)	(308		)	(82		)	—
Other current assets	(1,800		)	—			(1,523		)	646
Other assets, net	(54		)	(104		)	(199		)	(320		)
Accounts payable	(218		)	(954		)	1,934			1,242
Accrued gas purchases	(3,991		)	3,825			14,881			(8,113		)
Accrued expenses and other current liabilities	4,410			268			1,997			(922		)
Other liabilities	(811		)	392			(22		)	259
Net cash provided (used) in operating activities	10,432			13,791			(6,531		)	14,589
Cash flows from investing activities
Acquisition of operating assets from Enbridge Midcoast Energy, LP	—			—			(150,818		)	—
Acquisition of 50% interest in Burns Point Gas Plant from Marathon Oil Company	(35,500		)	—			—			—
Additions to property, plant and equipment	(6,369		)	(10,268		)	(1,158		)	(853		)
Proceeds from disposals of property, plant and equipment	125			—			—			—
Net cash provided (used) in investing activities	(41,744		)	(10,268		)	(151,976		)	(853		)
Cash flows from financing activities
Unit holder distributions	(43,546		)	(11,779		)	—			—
Contributions from parent	—			—			—			111,103
Proceeds upon issuance of common units to public, net of offering costs	69,085			—			—			—
Unit holder contributions	—			12,000			100,000			—
LTIP tax netting unit repurchase	(215		)	—			—			—
Distributions to parent	—			—			—			(25,772		)
Payments on other loan	(615		)	(1,000		)	(89		)	—
Borrowings on other loan	—			800			903			—
Repayments of notes to affiliates	—			—			—			(39,339		)
Deferred debt issuance costs	(2,489		)	—			(2,158		)	—
Borrowings on long-term debt	130,570			26,500			63,000			—
Payments on long-term debt	(120,670		)	(31,130		)	(2,000		)	(60,000		)
Net cash provided (used) in financing activities	32,120			(4,609		)	159,656			(14,008		)
Net increase (decrease) in cash and cash equivalents	808			(1,086		)	1,149			(272		)
Cash and cash equivalents
Beginning of period	63			1,149			—			421



End of period	$	871	$	63	$	1,149	$	149
Supplemental cash flow information
Interest payments	$	3,349	$	4,523	$	337	132
Supplemental non-cash information
Accrual of property, plant and equipment	$	75	$	—	$	—	$	—
Accrual of asset retirement obligation	$	872	$	6,058	$	—	$	—

The accompanying notes are an integral part of these consolidated financial statements.

American Midstream Partners’ LP and Subsidiaries

Notes to Consolidated Financial Statements

1. Organization and Basis of Presentation

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 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 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.

Since we acquired our assets from Enbridge Midcoast Energy, L.P. effective November 1, 2009, the financial and operational data for 2009 is bifurcated between the period that American Midstream Partners Predecessor (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. Between the date of inception and the date of acquisition of the assets discussed in Note 2 on November 1, 2009, no operating activity occurred in the partnership.

We have made reclassifications to amounts reported in prior period consolidated financial statements to conform to our current year presentation. These reclassifications did not have an impact on net income for the period previously reported.

Consolidation Policy

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold an undivided interest in a gas processing facility in which we are responsible for our proportionate share of the costs and expenses of the facility. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of this undivided interest.

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 (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 regulations 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 be recorded under GAAP for our regulated entities. As of December 31, 2011 and 2010, we had no such material 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) 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 year ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, respectively, we recognized the following revenues by category:



									Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009		Ten Months ended October 31, 2009
	2011			2010					Ten Months ended October 31, 2009
	(in thousands)
Revenue
Transportation - firm	$	10,504		$	10,610		$	2,274	$	10,616
Transportation - interruptible	3,583			3,313			444		1,662
Sales of natural gas, NGLs and condensate	233,319			197,706			30,078		129,673
Other	1,184			619			37		1,181
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—			—		—
Realized loss on expiration of commodity put contract	(308		)	—			—		—
Unrealized gain (loss) on commodity derivatives	(541		)	(308		)	—		—
Total revenue	$	244,743		$	211,940		$	32,833	$	143,132

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 at market prices. Where we provide processing services at the processing plants that we own, or obtain processing service for our own account under our own 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, NGLs 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 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 revenue is reasonably assured.

Interest in the Burns Point Plant

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 years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, the Partnership recorded no allowances for losses on accounts receivable.

Inventory

Inventory includes NGL product inventory. The Partnership records all product inventories at the lower of cost or market (“LCM”), which is determined on a weighted average basis and included within other current assets on the consolidated balance sheets.

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.

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 assets.

The Partnership calculated the fair value of assets acquired from Enbridge Pipelines, LP in November 2009 and the assets acquired from Marathon Oil Company in December 2011 with the assistance of an independent third party valuation firm. These valuations were performed primarily using a discounted cash flow model that included certain market assumptions related to future throughput discount rates. We created the projections and reviewed the calculations, assumptions and valuation methodology used to determine the fair value of the assets acquired. We 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 business, 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 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 years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009.

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 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

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 and is included in selling, general and administrative expenses in the consolidated statements of operations. The Texas margin tax is computed on our modified gross margin and was not significant for each of the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009.

Net income for financial statement purposes may differ significantly for 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 requirement 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 from the remediation of existing environmental contamination caused by past operations that do not benefit future period by preventing or eliminating future contamination. We record 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 regulation 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 date released by government organizations. Our estimates are subject to revision in future periods based on actual cost 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 in 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 offshore 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 of 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 exist 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 amount 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 sheets at fair market value. We record the fair market value of our derivative financial instruments in the consolidated balance sheet 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 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 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.

Comprehensive Income (loss)

The Partnership’s other comprehensive income (loss) is comprised of changes in the net pension asset or liability associated with the OPEB plan (Note 15). Comprehensive income (loss) for the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009 is as follows:



										Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009			Ten Months ended October 31, 2009
	2011			2010						Ten Months ended October 31, 2009
	(in thousands)
Net income (loss)	$	(11,698	)	$	(8,644	)	$	(6,992	)	$	(5,337	)
Unrealized gains (losses) on post retirement benefit
plan assets and liabilities	359			10			46			(201		)
Compreshensive income (loss)	$	(11,339	)	$	(8,634	)	$	(6,946	)	$	(5,538	)

Unit-Based Employee Compensation

We award unit-based compensation to management, non-management 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 equity compensation 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 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 use various assumptions and methods in estimating the fair values of our 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 our old and new credit facilities approximate fair value, because the interest rates on both facilities are variable.

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.

•

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 ant quoted prices in active markets for the identical instrument, as a 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.

•

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 extinguishment include any associated unamortized debt issue costs.

Limited Partners’ Net Income (Loss) Per Unit

We compute limited partners’ net income (loss) per unit by dividing our limited partners’ interest in net income (loss) by the weighted average number of units outstanding during the period. The overall computation, presentation and disclosure of our limited partners’ net income (loss) per unit are made in accordance with the FASB Accounting Standards Codification (ASC) Topic 260 “Earnings per Share”.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRS. The ASU amends previously issued authoritative guidance and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the ASU clarifies the FASB’s intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. This guidance will not have an impact on our financial position or results of operations.

In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income. The ASU amends previously issued authoritative guidance and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. These amendments remove the option under current U.S. GAAP to present the components of other comprehensive income as part of the statements of changes in stockholder’s equity. The adoption of this guidance will not have an impact on our financial position or results of operations, but will require the us to present the statements of comprehensive income separately from its statements of equity, as these statements are currently presented on a combined basis.

2. Acquisitions

Burns Point Plant Interest

On December 1, 2011, we acquired a 50% undivided interest (“Interest”) in the Burns Point Plant (“Plant”) from Marathon Oil Company (“Seller”) for total cash consideration of $35.5 million. No liabilities of the Seller were assumed. The purchase was effective November 1, 2011 (“Effective Date”) with our assumption of insurable risks, operating liabilities and entitlement to in-kind revenues as of that date. The remaining 50% undivided interest is owned by the Plant operator, Enterprise Gas Processing, LLC (“Operator”). The Plant, which is an unincorporated venture, is governed by a construction and operating agreement (“Agreement”).

The Plant is located in St. Mary Parish, Louisiana, and processes raw natural gas using a cryogenic expander. The Plant inlet volumes are sourced from offshore natural gas production via our Quivira system, Gulf South pipelines and onshore from individual producers near the plant. The Partnership’s Quivira system currently supplies approximately 85% of the inlet volume to the Plant. The residue gas is transported, via pipeline to Gulf South and Tennessee Gas Pipeline and the Y-grade liquid is transported via pipeline to K/D/S Promix, LLC (“Promix”), an Enterprise operated fractionator. The current capacity of the plant is 165 MMcf/d. The acquisition complemented our existing assets given the location of the Plant in comparison to the Quivira system and is included in our gathering and processing segment.

The Plant is not a legal entity but rather an asset that is jointly owned by the Operator and us. We acquired an interest in the asset group and do not hold an interest in a legal entity. Each of the owners in the asset group is proportionately liable for the liabilities. Outside of the rights and responsibilities of the Operator, we and the Operator have equal rights and obligations to the assets. Significant non-capital and maintenance capital expenditures, plant expansions and significant plant dispositions require the approval of both owners.

Under the terms of the Agreement, the Operator is required to provide monthly production allocation and expense statements to us and is not required to prepare and provide to us balance sheet information or stand-alone financial statements. Historically, balance sheet and stand-alone financial statements for the Plant have not been prepared and are, therefore, not available.

We looked at the governance structure of the Plant and applied the concepts discussed in ASC-810-10-45 (“Other Presentation Matters.”) We determined that while the facility is an unincorporated joint venture, the asset group is jointly controlled with the Operator.

We reviewed the requirements for the application of the equity method of accounting, given the joint control attribute of the Plant, and because the necessary complete Plant financial statements are not, nor expected to be, available from the Operator, we have elected to account for our Interest using the proportionate consolidation method. Our interest in the Plant is recorded in property, plant and equipment, net on the consolidated balance sheet and will be depreciated over 40 years. Under this method, we include in our consolidated statement of operations the value of our Plant revenues taken in-kind and the Plant expenses reimbursed to the Operator.




	(in thousands)
Consideration paid to seller
Cash consideration	$	35,500

Recognized amounts of identifiable assets acquired and liabilities assumed
Property, plant and equipment	$	36,065
Liabilities assumed	—

Total identifiable net assets	36,065
Bargain purchase (gain)	(565		)

	$	35,500

Fair value of the assets calculated under the market participant approach was in excess of cash consideration paid resulting in a $0.6 million bargain purchase gain.

Pro forma consolidated information

The following unaudited pro forma consolidated information sets forth our unaudited historical and pro forma consolidated statements of operations for the years ended December 31, 2011 and 2010.

The unaudited pro forma consolidated statements of operations for the years ended December 31, 2011 and 2010, give effect to the acquisition by us of the Interest as if it had occurred on January 1, 2010.

The unaudited pro forma adjustments are based on available information and certain assumptions we believe are reasonable.

The unaudited pro forma consolidated financial information is for informational purposes only and is not intended to represent or be indicative of the consolidated results of operations or financial position that we would have reported had this acquisition been completed on the date indicated and should not be taken as representative of its future consolidated results of operations or financial position. Further, the unaudited pro forma consolidated statement of operations is not indicative of the operations going forward because it necessarily excludes various operating expenses.



	Year Ended December 31, 2011										Year Ended December 31, 2010
	American Midstream Partners, LP as previously reported			Pro forma adjustments				American Midstream Partners, LP pro forma			American Midstream Partners, LP as previously reported			Pro forma adjustments				American Midstream Partners, LP pro forma
	(unaudited in thousands, except per unit amounts)
Revenue	$	248,282		$	5,165		(a)	$	253,447		$	212,248		$	4,645		(a)	$	216,893
Realized gain (loss) on early termination of commodity derivatives	(2,998		)					(2,998		)	—							—
Unrealized gain (loss) on commodity derivatives	(541		)					(541		)	(308		)					(308		)
Total revenue	244,743			5,165				249,908			211,940			4,645				216,585
Operating expenses:
Purchases of natural gas, NGLs and condensate	202,403							202,403			173,821							173,821
Direct operating expenses	12,856			1,290			(b)	14,146			12,187			1,805			(b)	13,992
Selling, general and administrative expenses	10,794							10,794			7,120							7,120
Advisory services agreement termination fee	2,500							2,500			—							—
Transaction expenses	282							282			303							303
Equity compensation expense	3,357							3,357			1,734							1,734
Depreciation expense	20,705			751			(c)	21,456			20,013			902			(c)	20,915
Total operating expenses	252,897			2,041				254,938			215,178			2,707				217,885
Gain on purchase of assets	565			(565		)	)(g)	—			—			565			(e)	565
Gain (loss) on sale of assets, net	399							399			—							—
Operating income (loss)	(7,190		)	2,559				(4,631		)	(3,238		)	2,503				(735		)
Other income (expenses):
Interest expense	(4,508		)	(2,602		)	)(d)(f)	(7,110		)	(5,406		)	(2,703		)	)(d)(f)	(8,109		)
Net income (loss)	$	(11,698	)	$	(43	)	)	$	(11,741	)	$	(8,644	)	$	(200	)	)	$	(8,844	)
General partner’s interest in net income (loss)	(233		)	(1		)	)	(234		)	(173		)	(4		)	)	(177		)
Limited partners’ interest in net income (loss)	$	(11,465	)	$	(42	)	)	$	(11,507	)	$	(8,471	)	$	(196	)	)	$	(8,667	)
Limited partners’ net income (loss) per unit	$	(1.64	)	$	(0.01	)	)	$	(1.65	)	$	(1.66	)	$	(0.04	)	)	$	(1.70	)
Weighted average number of units used in computation of limited partners’ net income (loss) per unit	6,997			6,997				6,997			5,099			5,099				5,099

Pro forma adjustments:


(a)	Assumes the value of allocated in-kind revenues from the beginning of the period.


(b)	Assumes allocated Plant direct operating costs and administrative fees from the beginning of the period.


(c)	Assumes depreciation expense from the beginning of the period, calculated on a straight-line basis over a 40 year useful life.


(d)	Assumes interest expense from the beginning of the period at the Partnership’s weighted average interest rate of 7.21% for the ten months ended October 31, 2011 and 7.48% for the year ended December 31, 2010.


(e)	Assumes a gain on purchase resulting from the difference between the cash consideration paid of $35.5 million and the fair value of the Interest of $36.1 million.


(f)	Assumes the straight-line amortization additional debt issuance costs over the remaining life of the credit facility, or 57 months, from the beginning of the period.


(g)	Elimination of bargain purchase gain which was assumed to have occurred at the beginning of the period presented.

Enbridge Assets

Effective November 1, 2009, American Midstream, LLC, a wholly owned subsidiary, acquired certain pipeline assets from Enbridge Midcoast Energy, LP, for an aggregate purchase price of $158.0 million. 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, and as such we estimated the fair value of each property as of the acquisition date (the date on which we 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. We 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.

The following table summarizes the consideration paid to the seller and the amounts of 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 $0.3 million and $6.4 million have been recorded in the statements of operations under the caption “Transaction expenses” for the year ended December 31, 2010 and the period ended December 31, 2009, 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 as 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; however, for the years ended December 31, 2011 and 2010 and the period ended December 31, 2009, no allowances on or write-offs of accounts receivable were recorded.

Enbridge Marketing (US) L.P., ConocoPhillips Corporation, Dow Chemical and ExxonMobil Corporation were significant customers, representing at least 10% of our consolidated revenue in the consolidated statement of operations in one or more of the periods presented, accounting for $44.8 million, $100.7 million, $15.7 million and $38.0 million, respectively, for the year ended December 31, 2011, $63.9 million, $53.4 million, $16.4 million and $22.9 million, respectively, for year ended December 31, 2010 and $17.8 million, $5.0 million, $3.1 million and $0.1 million, respectively, for the period ended December 31, 2009.

4. Other Current Assets



	December 31,
	2011		2010
	(in thousands)
Other receivables	$	663	$	30
Construction, operating and maintenance agreement (“COMA”)	623		—
Prepaid insurance—current portion	567		767
Other prepaid amounts	508		608
Gas imbalances receivable	852		—
NGL inventory	96		101
Other current assets	14		17
	$	3,323	$	1,523

For the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, we recorded no LCM write-downs on our inventory.

5. Derivatives

Commodity derivatives

To minimize the effect of a downturn in commodity prices and protect our profitability and the economics of our development plans, we enter into commodity economic hedge contracts from time to time. The terms of the 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.

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 NGL swap contracts and entering into new NGL swap contracts with an existing counterparty that extend through the end of 2012. A $3.0 million realized loss resulting from the early termination of these swap contracts was recorded in the consolidated statement of operations for year ended December 31, 2011.

We may be required to post collateral with our counterparty in connection with our derivative positions. As of December 31, 2011, we had no posted collateral with our counterparty. The counterparty is not required to post collateral with us in connection with their derivative positions. Netting agreements are in place with our counterparty allowing us to offset our commodity derivative asset and liability positions.

As of December 31, 2011, the aggregate notional volume of our commodity derivatives was 11.4 million NGL gallons.

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 fair value of the derivatives recorded in the consolidated 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 non-cash earnings volatility due to changes in the underlying commodity price indices or interest rates.

As of December 31, 2011 and 2010, the fair value associated with our derivative instruments were recorded in our consolidated balance sheets, under the caption Risk management assets and Risk management liabilities, as follows:



	December 31,
	2011		2010
	(in thousands)
Risk management assets:
Commodity derivatives	$	456	$	—
Risk management liabilities:
Commodity derivatives	$	635	$	—

For the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, we recorded the following realized and unrealized mark-to-market (losses):



										Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009			Ten Months ended October 31, 2009
	2011			2010						Ten Months ended October 31, 2009
	(in thousands)
Commodity derivatives	$	(849	)	$	(308	)	$	—		$	—
Interest rate derivatives	—			(77		)	(5		)	—
	$	(849	)	$	(385	)	$	(5	)	$	—

Fair Value Measurements

Our 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). Contracts classified as Level 3 are valued using price inputs available from public markets to the extent that the markets are liquid for the relevant settlement periods.



										Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009			Ten Months ended October 31, 2009
	2011			2010						Ten Months ended October 31, 2009
	(in thousands)
Fair value asset (liability), beginning of period	$	—		$	77		$	—		$	—
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—			—			—
Realized (loss) on expiration of commodity put Contract	(308		)	—			—			—
Unrealized gain (loss) on commodity derivatives	(541		)	(308		)	—			—
Unrealized gain (loss) on interest rate caps	—			(77		)	(5		)	—
Purchases	670			308			82			—
Settlements	2,998			—			—			—
Fair value asset (liability), end of period	$	(179	)	$	—		$	77		$	—

Also included in revenue were ($1.6) million and $nil million in realized gains (losses) for the years ended December 31, 2011 and 2010, respectively, representing our monthly swap settlements. No such gains (losses) were recorded for the periods ended December 31, 2009 and October 31, 2009.

6. Property, Plant and Equipment, Net

Property, plant and equipment, net, as of December 31, 2011 and 2010 were as follows:



		December 31,
	Useful Life	2011			2010
		(in thousands)
Land		$	41		$	41
Buildings and improvements	4 to 40	1,490			1,467
Processing and treating plants	8 to 40	49,396			13,010
Pipelines	5 to 40	149,040			143,805
Compressors	4 to 20	8,154			7,163
Equipment	8 to 20	1,580			1,711
Computer software	5	1,529			1,390
Total property, plant and equipment		211,230			168,587
Accumulated depreciation		(40,999		)	(21,779		)
Property, plant and equipment, net		$	170,231		$	146,808

Of the gross property, plant and equipment balances at December 31, 2011 and 2010, $24.0 million and $24.3 million, respectively, was related to AlaTenn and Midla, our FERC regulated interstate 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 then 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 years ended December 31, 2011 and 2010, we recognized $0.9 million and $6.1 million, respectively, of ARO which is included in other liabilities for specific assets that we intend to retire for operational purposes.

We recorded accretion expense, which is included in depreciation expense, in our consolidated statements of operations of $1.4 million, $1.2 million, $nil and $0.1 million for the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, respectively, in our consolidated statements of operations related to these AROs.

No assets were legally restricted for purposes of settling our ARO liabilities during the years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009. The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for years ended December 31, 2011 and 2010 and the periods ended December 31, 2009 and October 31, 2009, respectively:



								Predecessor
	For the Year Ended December 31,					Period from August 20, 2009 (Inception Date) to December 31, 2009		Ten Months ended October 31, 2009
	2011			2010				Ten Months ended October 31, 2009
	(in thousands)
Balance at beginning of period	$	7,249		$	—	$	—	$	2,006
Additions	872			6,058		—		—
Reductions	(920		)	—		—		—
Expenditures	(501		)	—		—		—
Accretion expense	1,393			1,191		—		108
Balance at end of period	$	8,093		$	7,249	$	—	$	2,114

In August 2011, we sold an abandoned portion of pipe for which we had recorded an ARO. As a result of this sale, we are no longer responsible for the costs of abandonment on this pipe and have reduced our ARO during 2011 by $0.5 million during 2011. In December 2011, we completed the abandonment of the West Cameron Pipeline at a cost of $0.5 million. Upon the completion of this project we reduced our ARO by $0.4 million.

8. Other Assets, Net

Other assets, net were as follows:



	December 31,
	2011		2010
	(in thousands)
Deferred financing costs	$	2,545	$	1,338
Other post retirement benefit plan assets, net	966		450
Prepaid amounts—long term	139		140
Security deposits	57		57
	$	3,707	$	1,985

Deferred financing costs

During the years ended December 31, 2011 and 2010 and the period ended December 31, 2009, deferred financing costs related to the term loan portion of our credit facility were amortized using the effective interest rate over the term of the term credit facility which was retired on August 1, 2011. 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 years ended December 31, 2011 and 2010 and the period ended December 31, 2009, we recorded deferred financing costs of $1.3 million, $2.2 million and $0.1 million, respectively.

9. Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities were as follows:



	December 31,
	2011		2010
	(in thousands)
Deferred revenue—short term	$	2,314	$	210
Accrued salaries	1,542		957
Accrued expenses	953		839
Construction operating and maintenance agreement deposits	710		—
Gas imbalances payable	1,200		—
Contract obligations—short term	240		240
Accrued interest payable	123		407
Other	4		23
	$	7,086	$	2,676

10. Other Liabilities

Other liabilities were as follows:



	December 31,
	2011		2010
	(in thousands)
Deferred revenue—long term	$	351	$	528
Asset retirement obligations	8,093		7,249
Contract obligations—long term	88		208
Other deferred expenses	80		93
	$	8,612	$	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, which was repayable in equal monthly installments of less than $0.1 million through October 1, 2011.

12. Long-Term Debt

On November 4, 2009, we entered into an $85 million secured credit facility (“old credit facility”) with a consortium of lending institutions. The old credit facility was composed of a $50 million term loan facility and a $35 million revolving credit facility.

That credit facility provided for a maximum borrowing equal to the lesser of (i) $85 million less required amortization of term loan payments and (ii) 3.50 times adjusted consolidated EBITDA. We could have elected to have the loans under this credit facility bear interest at either (i) 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 paid a facility fee of 1.0% per annum. In December 2009 we entered into an interest rate cap with participating lenders that effectively caped our Eurodollar-based rate exposure on that portion of our debt at 4.0%. The interest rate caps expired in December 2011. Prior to our initial public offering the weighted average interest rate on borrowings under our old credit facility was approximately 7.66%, 7.48% and 5.79% for the 7 months ended July 31, 2011 (date of termination), the year ended December 31, 2010 and the period ended December 31, 2009, respectively.

On August 1, 2011, we terminated the old credit facility and entered into our $100 million revolving credit facility (“new credit facility’). This new facility also contains a $50 million accordion feature which could bring the total facility commitment to $150 million.

The new credit facility provides for a maximum borrowing equal to the lesser of (i) $100 million or (ii) 4.50 times adjusted consolidated EBITDA. We may elect to have loans under the new credit facility bear interest either at a Eurodollar-based rate plus a margin ranging from 2.25% to 3.50% depending on our total leverage ratio then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (a) the Federal Funds Rate plus 1/2 of 1% (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate”, and (c) the Eurodollar Rate plus 1.00% plus a margin ranging from 1.25% to 2.50% depending on the total leverage ratio then in effect. We also pay a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan. Following our initial public offering the weighted average interest rate on borrowings under our new credit facility was 4.65% for the 5 months ended December 31, 2011. The blended weighted average interest rate for the year ended December 31, 2011 was 6.71%.

Our obligations under the new credit facility are secured by a first mortgage in favor of the lenders in our real property. Advances made under the credit facility are guaranteed on a senior unsecured basis by our subsidiaries (“Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The terms of the new 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, August 1, 2016.

The new 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 4.50 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, 2011.

Our outstanding borrowings under the new credit facility at December 31, 2011 and the old credit facility at December 31, 2010, respectively, were:



	December 31,
	2011		2010
	(in thousands)
Term loan facility	$	—	$	45,000
Revolving loan facility	66,270		11,370
	66,270		56,370
Less: current portion	—		6,000
	$	66,270	$	50,370

At December 31, 2011 and 2010, respectively, letters of credit outstanding under the new and old credit facilities were $0.6 million.

In connection with our new credit facility and amendments thereto, we incurred $2.5 million in debt issuance costs which are being amortized on a straight-line basis over the term of the new credit facility. In addition, we recognized a $0.6 million loss upon the early termination of our old credit facility which has been included in interest expense in our consolidated statement of operations.

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 in 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 that may be made pursuant to the incentive distribution rights that are nonvoting limited partner interests held by our general partner.

On August 1, 2011, we closed our initial public offering (the “IPO”) of our 3,750,000 common units at an offering price of $21 per unit. After deducting underwriting discounts and commissions of $4.9 million paid to the underwriters, offering expenses of $4.2 million and a structuring fee of $0.6 million, the net proceeds from our initial public offering were $69.1 million. We used all of the net offering proceeds from our initial public offering for the uses described in the Prospectus.

Immediately prior to the closing of our IPO the following recapitalization transactions occurred:


•	each common unit held by AIM Midstream Holdings 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;


•	the common units held by AIM Midstream Holdings then converted into 801,139 common units and 4,526,066 subordinated units;


•	each general partner unit held by our general partner 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 general partner’s long term incentive plan (the “LTIP”), 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; and


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

In connection with the closing of our IPO and immediately following the recapitalization transactions, the following transactions also occurred:


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


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

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.

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.

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.

Distributions

We made distributions of $9.8 million and $11.8 million for years ended December 31, 2011 and 2010, respectively. No distributions were made during the period ended December 31, 2009. We made no distributions in respect of our general partner’s incentive distribution rights during any of the periods presented. We have neither adopted a policy nor were we required to make minimum distributions during the periods presented in these financial statements.

In addition to the distributions described above, in August 2011 we made a special distribution of $33.7 million to AIM Midstream Holdings, participants in our LTIP holding common units and our general partner as described in the Prospectus.

The number of units outstanding was as follows:



	December 31,
	2011	2010
	(in thousands)
Limited partner common units	4,561	5,363
Limited partner subordinated units	4,526	—
General partner units	185	109

The outstanding units noted above reflect the retroactive treatment of the reverse unit split resulting from the recapitalization described above.

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 an LTIP for its employees, 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 LTIP. The LTIP currently permits the grant of awards that include phantom units that typically vest ratably over four years and may also include distribution equivalent rights (“DER”s), covering an aggregate of 303,601 of our units. A DER entitles the grantee to a cash payment equal to the cash distribution made by us with respect to a unit during the period such DER is outstanding. At December 31, 2011 and 2010, 54,827 and 62,246 units, respectively, were available for future grant under the LTIP giving retroactive treatment to the reverse unit split described in Note 13 “Partners’ Capital”.

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 units, our general partner has not historically settled these awards in cash. Although other types of awards are contemplated under the LTIP, the only currently outstanding awards are phantom units without DERs.

Grants issued under the LTIP vest in increments of 25% on each grant anniversary date and do not contain any vesting requirements other than continued employment.

Prior to our initial public offering, 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:



	For the Year Ended December 31,				Period from August 20, 2009 (Inception Date) to December 31, 2009
	2011		2010
	(in thousands)
Outstanding at beginning of period	205,864		175,236		—
Granted	19,414		74,437		175,236
Vested	(62,418	)	(43,809	)	—
Outstanding at end of period	162,860		205,864		175,236
Fair value per unit	14.70 to $19.69		14.70 to $16.15		$	16.15

The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our units at the grant date. Compensation costs related to these awards including amortization, modification costs, DER payments and the cost of the DER buy-out for the years ended December, 2011 and 2010 and the period ended December 31, 2009 was $3.4 million, $1.7 million and $0.2 million, respectively, which is classified as equity compensation expense in the consolidated statement of operations and the non-cash portion in partners’ capital on the consolidated balance sheet.

In June 2011, certain existing LTIP grant agreements were modified to exclude the DER provision in exchange for a cash payment of $1.5 million which has been included in equity compensation expense in the consolidated statement of operations. The total fair value of vesting units at the time of vesting was $1.2 million and $0.9 million for the years ending December 31, 2011 and 2010, respectively. No units vested during the period ended December 31, 2009.

The total compensation cost related to unvested awards not yet recognized at December 31, 2011 and 2010 was $2.7 million and $3.8 million, respectively, and the weighted average period over which this cost is expected to be recognized as of December 31, 2011 is approximately 2.1 years.

15. Post-Employment Benefits

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”).

The tables below detail the changes in the benefit obligation, the fair value of the plan assets and the recorded asset or liability of the OPEB Plan using the accrual method.



	OPEB Plan
										Predecessor
	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009			Ten Months ended October 31, 2009
	2011			2010						Ten Months ended October 31, 2009
	(in thousands)
Change in benefit obligation
Obligation, beginning of period	$	869		$	734		$	—		$	741
Obligation assumed from the acquisition from Enbridge	—			—			771			—
Service cost	3			10			2			8
Interest cost	22			43			7			36
Actuarial (gain) loss	(367		)	112			(44		)	10
Benefits paid	(61		)	(30		)	(2		)	(24		)
Benefit obligation, ending	$	466		$	869		$	734		$	771
Change in plan assets
Fair value of plan assets, beginning of period	$	1,319		$	1,174		$	—		$	999
Plan assets acquired from Enbridge	—			—			1,165			—
Actual return on plan assets	99			61			11			122
Employer’s contributions	90			113			—			68
Benefits paid	(76		)	(29		)	(2		)	(24		)
Fair value of plan assets, ending	$	1,432		$	1,319		$	1,174		$	1,165
Funded status
Funded status	$	966		$	450		$	440		$	257

The amounts of plan assets recognized in our consolidated balance sheets were as follows:



	OPEB Plan
	December 31,
	2011		2010
	(in thousands)
Other assets	$	966	$	450
	$	966	$	450

The amounts included in accumulated other comprehensive income at December 31, 2011 and 2010 that have not been recognized as components of net periodic benefit expense are $0.4 million and $0.1 million, respectively, which relate to net gains.

Components of Net Periodic Benefit Cost and Other amounts Recognized in Other Comprehensive Income



	OPEB Plan
	December 31,
	2011			2010
	(in thousands)
Net Periodic (Benefit) Cost
Service cost	$	3		$	10
Interest cost	22			43
Expected return on plan assets	(60		)	(53		)
Amortization of net (gain) loss	(47		)	—
Net periodic (benefit) cost	$	(82	)	$	—
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
Net loss (gain)	(359		)	(10		)
Total recognized in other comprehensive income	(359		)	(10		)
Total recognized in net periodic benefit cost and other comprehensive income	$	(441	)	$	(10	)

The estimated net gain that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is less than $0.1 million.

Economic assumptions

The assumptions made in measurement of the projected benefit obligations or assets of the OPEB Plan were as follows:



	OPEB Plan
	2011		2010		2009
Discount rate	3.96	%	5.50	%	6.00	%
Expected return on plan assets	4.50	%	4.50	%	4.50	%

A one percent increase in the assumed medical and dental care trend rate would result in an increase of less than $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 less than $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 2011, 2010 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
	OPEB Plan
	(in thousands)
For the year ending
2012	$	40
2013	39
2014	34
2015	33
2016	31
Five years thereafter	133

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.

Future contributions to the Plans

We expect to make contributions to the OPEB Plan for the year ending December 31, 2012 of $0.1 million.

Plan assets

The weighted average asset allocation of our OPEB Plan at the measurement date by asset category, which are all classified as Level 1 investments, are as follows:



	OPEB Plan
	2011		2010		2009
Fixed income (a)	72.1	%	70.7	%	76.7	%
Cash and short term assets (b)	27.9	%	29.3	%	23.3	%
Total	100.0	%	100.0	%	100.0	%


(a)	United States government securities, municipal corporate bonds and notes and asset backed securities


(b)	Cash and securities with maturities of one year or less

16. Commitments and Contingencies

Environmental matters

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.

Commitments and contractual obligations

Future non-cancelable commitments related to certain contractual obligations as of December 31, 2011 are presented below:



	Payments Due by Period (in thousands)
	Total		2012		2013		2014		2015		2016		Thereafter
Operating leases and service contract	$	1,774	$	415	$	361	$	377	$	367	$	131	$	123
ARO	8,093		—		—		—		—		8,093		—
Total	$	9,867	$	415	$	361	$	377	$	367	$	8,224	$	123

For the periods indicated, total expenses related to operating leases, asset retirement obligations, land site leases and right-of-way agreements were:



	For the Year Ended December 31,				Period from August 20, 2009 (Inception Date) to December 31, 2009
	2011		2010
	(in thousands)
Operating leases	$	803	$	757	$	60
ARO	1,393		1,191		—
	$	2,196	$	1,948	$	60

Bazor Ridge Emissions Matter

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 governmental authorities. We did not make any such EPCRA notifications. In July 2011, we self-reported these issues to the MDEQ and the EPA.

American Midstream Partner’s LP and Subsidiaries

Notes to Consolidated Financial Statements (continued)

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.

We are in communication with regulatory officials at both the MDEQ and the EPA regarding the Bazor Ridge plant reporting issue.

17. 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 years ended December 31, 2011 and 2010 and the period ended December 31, 2009 administrative and operational services expenses of $9.6 million, $7.6 million and $1.1 million, respectively, were charged to us by our general partner.

Prior to our IPO, we had 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 provided 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 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 years ended December 31, 2011 and 2010 and the period ended December 31, 2009, $0.2 million, $0.3 million and less than $0.1 million had been recorded to selling, general and administrative expenses under this agreement.

On August 1, 2011 and in connection with our IPO, we terminated the advisory services agreement in exchange for a payment of $2.5 million.

Predecessor Related Party Transactions

The Predecessor was wholly owned by Enbridge Midcoast Energy, L.P. (“Enbridge”) and its subsidiaries. For the ten months ended October 31, 2009, the Predecessor received contributions by Enbridge of $111.1 million and paid distributions to the Predecessor’s parent of $25.8 million.

Enbridge 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 $6.7 million for the period ended October 31, 2009 and were allocated based primarily on a percentage of revenue, which we believe is reasonable. The Predecessor recorded operating revenues to Enbridge affiliates for natural gas gathering, treating, processing, marketing and transportation services of $73.9 million for the period ended October 31, 2009. The Predecessor also purchased natural gas from Enbridge affiliates for sale to third-parties at market prices on the date of purchase of $0.9 million for the period ended October 31, 2009.

Additionally, for the ten months ended October 31, 2009, the Predecessor had interest income of $0.4 million and interest expense of $4.1 million related to financing transactions with affiliates.

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

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.

The following tables set forth our segment information for the periods indicated, in thousands:



	Gathering and Processing			Transmission		Total
Year ended December 31, 2011
Revenue	$	181,517		$	66,765	$	248,282
Segment gross margin (a),(b)	32,450			13,737		46,187
Realized gain (loss) on early termination of commodity derivatives	(2,998		)	—		(2,998		)
Realized (loss) on expiration of commodity put contracts	(308		)	—		(308		)
Unrealized gain (loss) on commodity derivatives	(541		)	—		(541		)
Direct operating expenses						12,856
Selling, general and administrative expenses						10,794
Advisory services agreement termination fee						2,500
Transaction expenses						282
Equity compensation expense						3,357
Depreciation expense						20,705
Gain (loss) on acquisition of assets						565
Gain (loss) on sale of assets, net						399
Interest expense						4,508
Net income (loss)						(11,698		)



	Gathering and Processing		Transmission		Total
Year ended December 31, 2010
Revenue	$	158,455	$	53,485	$	211,940
Segment gross margin (a),(b)	24,595		13,524		38,119
Realized gain (loss) on early termination of commodity derivatives	—		—		—
Unrealized gain (loss) on commodity derivatives	—		—		—
Direct operating expenses					12,187
Selling, general and administrative expenses					7,120
Advisory services agreement termination fee					—
Transaction expenses					303
Equity compensation expense					1,734
Depreciation expense					20,013
Gain (loss) on acquisition of assets					—
Gain (loss) on sale of assets, net					—
Interest expense					5,406
Net income (loss)					(8,644		)



	Gathering and Processing		Transmission		Total
Period from August 9, 2009 (inception date) to December 31, 2009
Revenue	$	27,857	$	4,976	$	32,833
Segment gross margin (a)	3,698		2,542		6,240
Realized gain (loss) on early termination of commodity derivatives
Unrealized gain (loss) on commodity derivatives
Direct operating expenses					1,594
Selling, general and administrative expenses					1,196
Advisory services agreement termination fee					—
Transaction expenses					6,404
Equity compensation expense					150
Depreciation expense					2,978
Gain (loss) on acquisition of assets					—
Gain (loss) on sale of assets, net					—
Interest expense					910
Net income (loss)					(6,992		)



	Gathering and Processing		Transmission		Total
Ten months ended October 31, 2009 (Predecessor)
Revenue	$	132,957	$	10,175	$	143,132
Segment gross margin (a)	20,024		9,881		29,905
Realized gain (loss) on early termination of commodity derivatives					—
Unrealized gain (loss) on commodity derivatives					—
Direct operating expenses					10,331
Selling, general and administrative expenses					8,553
Advisory services agreement termination fee					—
Transaction expenses					—
Equity compensation expense					—
Depreciation expense					12,630
Gain (loss) on acquisition of assets					—
Gain (loss) on sale of assets, net					—
Interest expense					3,728
Net income (loss)					$	(5,337	)

(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)

Realized gains (losses) from the early termination of commodity derivatives and unrealized gains (losses) from derivative mark-to-market adjustments are included in total revenue and segment gross margin in our Gathering and Processing segment for the year ended December 31, 2010. Effective January 1, 2011, we changed our segment gross margin measure to exclude unrealized non-cash mark-to-market adjustments related to our commodity derivatives. For the year ended December 31, 2011, $0.5 million in unrealized gains (losses) on commodity derivatives were excluded from our Gathering and Processing segment gross margin. Effective April 1, 2011 we changed our segment gross margin measure to exclude realized early termination costs on commodity derivatives. For the year ended December 31, 2011, ($3.0) million in realized gains (losses) on the early termination of commodity derivatives were excluded from our Gathering and Processing segment gross margin.

Asset information, including capital expenditures, by segment is not included in reports used by our management to monitor our performance and therefore is not disclosed.

For the purposes of our Gathering and Processing segment, for the years ended December 31, 2011 and 2010 and the period ended December 31, 2009, 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 our Gathering and Processing segment. Our segment revenue derived from Enbridge Marketing (US) L.P., ConocoPhillips Corporation and Dow Hydrocarbons and Resources represented $29.9 million, $100.7 million and $15.7 million of segment revenue for the year ended December 31, 2011, $47.3 million, $53.4 million and $16.4 million of segment revenue for the year ended December 31, 2010 and $14.7 million, $5.0 million and $3.1 million of segment revenue for the period ended December 31, 2009, respectively.

For purposes of our Transmission segment, for the years ended December 31, 2011 and 2010 and the period ended December 31, 2009, Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine Corporation represented significant customers, each representing more than 10% of our segment revenue in our Transmission segment in one or more of the periods presented. Our segment revenue derived from Enbridge Marketing (US) L.P. ExxonMobil Corporation and Calpine Corporation represented $15.0 million, $38.0 and $5.1 million of segment revenue for the year ended December 31, 2011, $16.6 million, $22.9 million and $5.1 million of segment revenue for the year ended December 31, 2010 and $3.0 million, $0.1 million and $0.9 million of segment revenue for the period ended December 31, 2009, respectively.

19. Net Income (Loss) per Limited and General Partner Unit

Net income (loss) is allocated to the general partner and the limited partners (common and subordinated unit holders) in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income (loss) per limited partner unit is calculated by dividing limited partners’ interest in net income (loss) by the weighted average number of outstanding limited partner units during the period.

Unvested unit-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.

We determined basic and diluted net income (loss) per general partner unit and limited partner unit as follows, in thousands except per unit amounts:



	For the Year Ended December 31,						Period from August 20, 2009 (Inception Date) to December 31, 2009
	2011			2010
	(in thousands)
Net (loss) attributable to general partner and limited partners	$	(11,698	)	$	(8,644	)	$	(6,992	)
Weighted average general partner and limited partner units outstanding(a)(b)	7,137			5,199			2,231
General partner and limited partner (loss) per unit (basic and diluted)	$	(1.64	)	$	(1.66	)	$	(3.13	)
Net (loss) attributable to limited partners	$	(11,465	)	$	(8,471	)	$	(6,852	)
Weighted average limited partner units outstanding(a)(b)	6,997			5,099			2,187
Limited partners’ net (loss) per unit (basic and diluted)	(1.64		)	$	(1.66	)	$	(3.13	)
Net (loss) attributable to general partner	$	(233	)	$	(173	)	$	(140	)
Weighted average general partner units outstanding	140			99			43
General partner net (loss) per unit (basic and diluted)	$	(1.66	)	$	(1.75	)	$	(3.26	)


(a)	Includes unvested phantom units with DERs, which are considered participating securities, of 205,864 and 175,236 as of December 31, 2010 and 2009, respectively. The DER’s were eliminated on June 9, 2011. There were no such unvested phantom units with DERs at December 31, 2011.


(b)	Gives effect to the reverse unit split as described in Note 13, “Partners’ Capital”.

20. Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2011 and 2010 are as follows:



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(in thousands expect per unit amounts)
Year ended December 31, 2011
Revenues	$	63,765		$	65,634		$	57,958		$	57,386		$	244,743
Gross margin (a)	12,312			10,617			9,646			13,612			46,187
Operating income (loss)	(2,246		)	(2,901		)	(3,375		)	1,332			(7,190		)
Net income (loss)	$	(3,510	)	$	(4,182	)	$	(4,167	)	$	161		$	(11,698	)
General partner’s interest in net income (loss)	(70		)	(84		)	(83		)	4			(233		)
Limited partners’ interest in net income (loss)	$	(3,440	)	$	(4,098	)	$	(4,084	)	$	157		$	(11,465	)
Limited partners’ net income (loss) per unit	$	(0.62	)	$	(0.74	)	$	(0.53	)	$	0.02		$	(1.64	)
Year ended December 31, 2010
Revenues	$	54,712		$	47,790		$	52,953		$	56,485		$	211,940
Gross margin (a)	9,748			8,947			8,437			10,987			38,119
Operating income (loss)	(97		)	(1,478		)	(1,941		)	278			(3,238		)
Net income (loss)	$	(1,454	)	$	(2,853	)	$	(3,360	)	$	(977	)	$	(8,644	)
General partner’s interest in net income (loss)	(29		)	(57		)	(67		)	(20		)	(173		)
Limited partners’ interest in net income (loss)	$	(1,425	)	$	(2,796	)	$	(3,293	)	$	(957	)	$	(8,471	)
Limited partners’ net income (loss) per unit	$	(0.29	)	$	(0.56	)	$	(0.66	)	$	(0.18	)	$	(1.66	)


(a)	For a definition of gross margin and a reconciliation to its mostly directly comparable financial measure calculated and presented in accordance with GAAP, please read note Note 18, Reporting Segments.

21. Subsequent Event

On January 24, 2012, we announced a distribution of $0.4325 per unit payable on February 10, 2012 to unitholders of record on February 3, 2012.

22. Subsidiary Guarantors

The Partnership has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities. The subsidiaries of the Partnership (the "Subsidiaries") will be co-registrants with the Partnership, and the registration statement will register guarantees of debt securities by one or more of the Subsidiaries (other than American Midstream Finance Corporation, a 100 percent owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of such debt securities). As of December 31, 2011, the Subsidiaries are 100 percent owned by the Partnership and any guarantees by the Subsidiaries will be full and unconditional. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership by dividend or loan. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by the Partnership, such guarantees will constitute joint and several obligations. None of the assets of the Partnership or the Subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.

23. Liquidity

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