Exhibit 99.1

 

RISK FACTORS

 

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

 

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

 

Risks Related to our Business

 

We are dependent on EQT for a substantial majority of our revenues and future growth. Therefore, we are indirectly subject to the business risks of EQT. We have no control over EQT’s business decisions and operations, and EQT is under no obligation to adopt a business strategy that favors us.

 

Historically, we have provided a substantial percentage of our natural gas transmission, storage and gathering services to EQT. During the year ended December 31, 2011 and the three-month period ended March 31, 2012, approximately 79% and 78%, respectively, of our revenues were from EQT. We expect to derive a substantial majority of our revenues from EQT for the foreseeable future. Therefore, any event, whether in our area of operations or otherwise, that adversely affects EQT’s production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of EQT, including the following:

 

·    natural gas price volatility may have an adverse effect on its drilling operations, revenue, profitability, future rate of growth and liquidity;

·    infrastructure capacity constraints and interruptions;

·    risks associated with the operation of its wells, pipelines and facilities, including potential environmental liabilities;

·    the availability of capital on a satisfactory economic basis to fund its operations;

·    its ability to identify production opportunities based on market conditions;

·    uncertainties inherent in projecting future rates of production;

·    its ability to develop additional reserves that are economically recoverable, to optimize existing well production and sustain production;

·    adverse effects of governmental and environmental regulation and negative public perception regarding its operations; and

·    the loss of key personnel.

 

Unless we are successful in attracting significant unaffiliated third-party customers, our ability to maintain or increase the capacity subscribed and volumes transported under service

 



 

arrangements on our transmission and storage system as well as the volumes gathered on our gathering system will be dependent on receiving consistent or increasing commitments from EQT. While EQT has dedicated acreage to, and entered into long-term firm transportation contracts on, our systems, it may determine in the future that drilling in areas outside of our current areas of operations is strategically more attractive to it and it is under no contractual obligation to maintain its production dedicated to us. For example, EQT Energy, LLC, or EQT Energy, a wholly-owned marketing affiliate of EQT, allowed a storage agreement with us for 3.6 Bcf of storage capacity and the associated firm transmission agreement to expire on March 31, 2012. This decision was likely due to lower natural gas price spreads and increased supply of natural gas from the Marcellus Shale. A reduction in the capacity subscribed or volumes transported, stored or gathered on our systems by EQT could have a material adverse effect on our business, financial condition, results or operations and ability to make quarterly cash distributions to our unitholders.

 

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 and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

 

In order to pay the minimum quarterly distribution of $0.3500 per unit, or $1.40 per unit on an annualized basis, we will require available cash of approximately $12.4 million per quarter, or $49.5 million per year, based on the number of common, subordinated and general partner units to be outstanding immediately after completion of this offering. We may not have sufficient available cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

·    the rates we charge for our transmission, storage and gathering services;

·    the level of firm transmission and storage capacity sold and volumes of natural gas we transport, store and gather for our customers;

·    regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm transmission and storage agreements;

·    the effect of seasonal variations in temperature on the amount of natural gas that we transport, store and gather;

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

·    the creditworthiness of our customers;

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

·    regulatory action affecting the supply of, or demand for, natural gas, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and

·    prevailing economic conditions.

 



 

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

 

·    the level and timing of capital expenditures we make;

·    the level of our operating and general and administrative expenses, including reimbursements to our general partner and its affiliates, including EQT, for services provided to us;

·    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 on distributions contained in our debt agreements;

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

·    other business risks affecting our cash levels.

 

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

 

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2011 or the twelve-month period ended March 31, 2012.

 

The amount of pro forma available cash generated during the year ended December 31, 2011 and the twelve-month period ended March 31, 2012 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units, but only approximately 81.1% and 80.7%, respectively, of the minimum quarterly distribution on all of our subordinated units for each such period. For a calculation of our ability to make cash distributions to our unitholders based on our pro forma results for the year ended December 31, 2011 and the twelve-month period ended March 31, 2012, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

 

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

 

The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions On Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve-month period ending June 30, 2013. We estimate that our total cash available for distribution for the twelve-month period ending June 30, 2013 will be approximately $54.5 million, as compared to approximately $44.9 million for the year ended December 31, 2011 and approximately $44.8 million for the twelve-month period ended March 31, 2012, in each case on a pro forma basis. A portion of the expected increase in cash available for distribution is attributable to increased revenues from usage fees from EQT based on current projections of production growth. To the extent this growth is not achieved, our revenues during the forecast period will be adversely affected. In addition, a portion of this

 



 

expected increase in cash available for distribution is attributable to revenues from additional firm capacity subscriptions associated with the Blacksville Compressor Station project, which is expected to be placed into service in the third quarter of 2012. To the extent the Blacksville Compressor Station is not placed into service in the third quarter of 2012 or we are not able to subscribe additional firm transmission capacity for the project, our revenues during the forecast period will be adversely affected. Furthermore, our forecast assumes that during the forecast period we will recover a portion of costs incurred in 2011 to comply with the Pipeline Safety Improvement Act of 2002; however the amount of such recovery is subject to FERC approval on an annual basis and it has not yet been approved and is subject to two protests. For additional information, please see “Business—Regulatory Environment—Pipeline Safety Tracker.” The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

 

Our natural gas transportation, storage and gathering services are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

 

Our interstate natural gas transportation and storage operations are regulated by the FERC under the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005. Our gathering operations are also regulated by the FERC in connection with our interstate transportation operations. Our system operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms and terms and conditions of service to our customers. Generally, the FERC’s authority extends to:

 

·    rates and charges for our natural gas transmission, storage and gathering services;

·    certification and construction of new interstate transmission and storage facilities;

·    abandonment of interstate transmission and storage services and facilities;

·    maintenance of accounts and records;

·    relationships between pipelines and certain affiliates;

·    terms and conditions of services and service contracts with customers;

·    depreciation and amortization policies;

·    acquisition and disposition of interstate transmission and storage facilities; and

·    initiation and discontinuation of interstate transmission and storage services.

 

Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust and unreasonable or unduly discriminatory. The maximum recourse rate that may be charged by our interstate pipeline for its transmission and storage services is established through the FERC’s ratemaking process. The maximum applicable recourse rate and terms and conditions for service are set forth in our FERC-approved tariff.

 



 

Pursuant to the NGA, existing interstate transportation and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) “recourse rates” (i.e., the maximum rates an interstate pipeline may charge for its services under its tariff) and (ii) “negotiated rates” which generally involve rates above the “recourse rates,” provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. As of March 31, 2012, approximately 46% of our system’s contracted firm transportation capacity was committed under such “negotiated rate” contracts, rather than recourse rate or discount rate contracts. There can be no guarantee that we will be allowed to continue to operate under such rate structures for the remainder of those assets’ operating lives. Any successful challenge against rates charged for our transportation and storage services could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

 

While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, the FERC has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline’s own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transmission facilities. We maintain rates and terms of service in our tariff for unbundled gathering services performed on our gathering facilities, which are connected to our transmission and storage system. Just as with rates and terms of service for transportation and storage services, our rates and terms of services for our gathering may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and changes to terms and conditions of service which we propose for our gathering service may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC.

 

The FERC’s jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to, acquisitions, facility maintenance, expansions, and abandonment of facilities and services. While the FERC exercises jurisdiction over the rate and terms of service for our gathering operations, our gathering facilities are not subject to the FERC’s certification and construction authority. Prior to commencing construction of new or existing interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or file to amend its existing certificate, from the FERC. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any refusal by an agency to issue authorizations or permits for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Such refusal or modification could materially and negatively impact the additional revenues expected from these projects.

 

FERC regulations also extend to the terms and conditions set forth in agreements for transportation and storage services executed between interstate pipelines and their customers.

 



 

These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline’s FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.

 

Under current policy, the FERC permits interstate pipelines to include an income tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines owned by partnerships or limited liability companies taxed as partnerships for federal income tax purposes, the tax allowance will reflect the actual or potential income tax liability on the FERC-jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. This policy was upheld on May 29, 2007 by the Court of Appeals for the District of Columbia Circuit. The FERC will determine, on a case-by-case basis, whether the owners of an interstate pipeline have such actual or potential income tax liability. In a future rate case, we may be required to demonstrate the extent to which inclusion of an income tax allowance in the applicable cost-of-service is permitted under the current income tax allowance policy. In addition, the FERC’s income tax allowance policy is frequently the subject of challenge, and we cannot predict whether the FERC or a reviewing court will alter the existing policy. If the FERC’s policy were to change and if the FERC were to disallow a substantial portion of our pipeline’s income tax allowance, our regulated rates, and therefore our revenues and ability to make distributions, could be materially adversely affected.

 

The FERC may not continue to pursue its approach of pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities.

 

Failure to comply with applicable provisions of the NGA, the NGPA, the Pipeline Safety Act of 1968 and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to $1,000,000 per day, per violation.

 

In addition, future federal, state, or local legislation or regulations under which we will operate our natural gas transportation, storage and gathering businesses may have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.

 

Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available for distribution to unitholders.

 

Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from existing wells and natural gas supply basins with

 



 

access to our systems will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers or lower natural gas prices could cause producers to determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in response to historically low natural gas prices, a number of large natural gas producers have recently announced their intention to re-evaluate and/or reduce their drilling programs in certain areas, including the Appalachian Basin. A reduction in the natural gas volumes supplied by EQT or other third party producers could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, stored and gathered on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies 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 near our systems and (ii) our ability to compete for volumes from successful new wells. While EQT has dedicated production from certain of its leased properties to us, 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 gathering system or the rate at which production from a well declines. In addition, we have no control over EQT or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other production and development costs.

 

Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquefied natural gas, or LNG; the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; 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 natural gas, LNG and other commodities. 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 systems. Because of these 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. Moreover, EQT may not develop the acreage it has dedicated to us. If reductions in drilling activity result in our inability to maintain levels of contracted capacity and throughput, it could reduce our revenue and impair our ability to make quarterly cash distributions to our unitholders.

 



 

The price of natural gas has been at historically low levels recently, with the five-year NYMEX natural gas futures price at $3.62 per MMbtu in April 2012, compared to a high of $11.51 per MMbtu in July 2008. As of May 31, 2012, the near month NYMEX natural gas futures price was $2.43 per MMbtu. The lower prices of natural gas are due in part to high levels of natural gas in storage, increased production, especially from unconventional sources, like shale plays, and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration, or EIA, the amount of natural gas produced in the continental United States increased 14.1% from 55.3 Bcf/d to 63.0 Bcf/d from 2008 to 2011. Furthermore, the amount of natural gas in storage in the United States has increased from approximately 1.6 Tcf as of March 31, 2011 to approximately 2.5 Tcf as of March 31, 2012, due to the unseasonably warm winter of 2011/2012 and to the decisions of many producers to store natural gas based on their expectation of higher prices in the future. In response to lower natural gas prices, the number of land-based natural gas drilling rigs in the continental United States has declined from approximately 1,403 as of December 31, 2008 to approximately 635 as of March 31, 2012 according to Smith Bits (a unit of Schlumberger).

 

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems in unconventional resource plays such as the Marcellus Shale, as the basins in those plays generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Furthermore, our gathering assets were initially constructed as a low-pressure system designed for shallow, vertical wells and Marcellus Shale production is increasingly from horizontal wells at higher pressure than our existing gathering assets were designed to handle. If natural gas prices remain low, production in the area around our low-pressure gathering system may continue to decline. Accordingly, volumes on our gathering system would need to be replaced at a faster rate to maintain or grow the current volumes than may be the case in other regions of production. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time.

 

If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas transported and stored on our systems would decline, which could have a material adverse effect on our business, financial condition and results of operations and on our ability to make quarterly cash distributions to our unitholders.

 

We may not be able to increase our third-party throughput and resulting revenue due to competition and other factors, which could limit our ability to grow and extend our dependence on EQT.

 

Part of our growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties. For the year ended December 31, 2011 and the three-month period ending March 31, 2012, EQT accounted for approximately 83% and 81%, respectively, of our transmission revenues, 77% and 74%, respectively, of our storage revenues, 64% and 64%, respectively, of our gathering revenues and 79% and 78%, respectively, of our total revenues. Our ability to increase our third-party throughput and resulting revenue is subject

 



 

to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when third-party shippers require it. To the extent that we lack available capacity on our systems for third-party volumes, we may not be able to compete effectively with third-party systems for additional natural gas production in our areas of operation.

 

We have historically provided transmission, storage and gathering services to third parties on only a limited basis, and we may not be able to attract material third-party service opportunities. Our efforts to attract new unaffiliated customers may be adversely affected by our relationship with EQT and our desire to provide services pursuant to fee-based contracts. Our potential customers may prefer to obtain services under other forms of contractual arrangements under which we would be required to assume direct commodity exposure, and potential customers may desire to contract for gathering services that are not subject to FERC regulation. In addition, we will need to continue to improve our reputation among our potential customer base for providing high quality service in order to continue to successfully attract unaffiliated third parties.

 

We are exposed to the credit risk of our customers in the ordinary course of our business.

 

We extend credit to our customers as a normal part of our business. As a result, we are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers. While we have established credit policies, including assessing the creditworthiness of our customers as permitted by our FERC-approved natural gas tariff, and requiring appropriate terms or credit support from them based on the results of such assessments, we may not have adequately assessed the creditworthiness of our existing or future customers. Furthermore, unanticipated future events could result in a deterioration of the creditworthiness of our contracted customers, including EQT. Any resulting nonpayment and/or nonperformance by our customers could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

 

Increased competition from other companies that provide transmission, storage or gathering services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.

 

Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete primarily with other interstate and intrastate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own transmission, storage or gathering services instead of using ours. Moreover, EQT and its affiliates are not limited in their ability to compete with us. Please read “Conflicts of Interest and Duties.”

 



 

The policies of the FERC promoting competition in natural gas markets are having the effect of increasing the natural gas transportation and storage options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored by our systems or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates.

 

Further, natural gas as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage and transportation services.

 

All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

 

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas, our revenues and cash available to make distributions to you could be adversely affected.

 

We depend upon third-party pipelines and other facilities that provide receipt and delivery options to and from our transmission and storage system. For example, our transmission and storage system interconnects with the following interstate pipelines: Texas Eastern, Dominion Transmission, Columbia Gas Transmission, Tennessee Gas Pipeline Company and National Fuel Gas Supply Corporation, as well as multiple distribution companies. Similarly, our gathering system has multiple delivery interconnects to the Dominion Transmission system. Additionally, substantially all of the natural gas that is gathered by our gathering system that requires processing and treating is handled by Dominion Transmission. In the event that our access to such facility was impaired or if we were unable to negotiate a processing and treating contract with another party on like terms, the amount of natural gas that our gathering system can gather and transport onto our transmission and storage system would be adversely affected, and which could reduce revenues from our gathering activities. Because we do not own these third party pipelines or facilities, their continuing operation is not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

 



 

Certain of the services we provide on our transmission and storage system are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.

 

It is possible that costs to perform services under “negotiated rate” contracts will exceed the negotiated rates. If this occurs, it could decrease the cash flow realized by our systems and, therefore, the cash we have available for distribution to our unitholders. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate,” which is generally above the FERC-regulated “recourse rate” for that service, and that contract must be filed with and accepted by the FERC. As of March 31, 2012, approximately 46% of our contracted transmission firm capacity was subscribed under such “negotiated rate” contracts. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. For example, on March 1, 2012, Equitrans made an annual filing with the FERC to recover costs it incurs to comply with the Pipeline Safety Improvement Act of 2002; however the amount of such recovery is subject to FERC approval. The 2012 filing has not yet been approved and is the subject of two protests. To the extent the FERC ultimately agrees with the protestors, the level of the surcharge, and thus the amount of the anticipated cost recovery, could be significantly reduced. For additional information, please see “Business—Regulatory Environment—Pipeline Safety Tracker.” If the level of the surcharge is reduced, we will not generally be able to adjust these “negotiated rate” contracts to take into account the increased costs we incur to comply with the Pipeline Safety Improvement Act of 2002. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, under current FERC policy is generally not recoverable from other shippers. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Revenues and Contract Mix.”

 

We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.

 

Our primary exposure to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. As of March 31, 2012, the weighted average remaining contract life based on total revenues for our firm transmission and storage contracts was approximately 9.5 years. The extension or replacement of existing contracts, including our contracts with EQT, depends on a number of factors beyond our control, including:

 

·    the level of existing and new competition to provide services to our markets;

·    the macroeconomic factors affecting natural gas economics for our current and potential customers;

·    the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

·    the extent to which the customers in our markets are willing to contract on a long-term basis; and

·    the effects of federal, state or local regulations on the contracting practices of our

 



 

customers.

 

Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

 

If the tariff governing the services we provide is successfully challenged, we could be required to reduce our tariff rates, which would have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

 

Any of our shippers, the FERC, or other interested stakeholders, such as state regulatory agencies, may challenge the maximum recourse rates or the terms and conditions of service included in our tariff. We do not have an agreement in place that would prohibit EQT or its affiliates from challenging our tariff. If any challenge were successful, among other things, the rates that we charge on our systems could be reduced. Successful challenges would have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

 

If we are unable to make acquisitions on economically acceptable terms from EQT or 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, including EQT. We have no contractual arrangement with EQT that would require it to provide us with an opportunity to offer to purchase midstream assets that it may sell. Accordingly, while we note elsewhere in this prospectus that we believe EQT will be incentivized pursuant to its economic relationship with us to offer us opportunities to purchase midstream assets, there can be no assurance that any such offer will be made. Furthermore, many factors could impair our access to future midstream assets and the willingness of EQT to offer us acquisition opportunities, including a change in control of EQT or a transfer the incentive distribution rights by our general partner to a third party. A material decrease in divestitures of midstream energy assets from EQT or otherwise would limit our opportunities for future acquisitions and could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

 

If we are unable to make accretive acquisitions from EQT or third parties, whether because, among other reasons, (i) EQT elects not to sell or contribute additional assets to us or to offer acquisition opportunities to us, (ii) we are unable to identify attractive third-party acquisition opportunities, (iii) we are unable to negotiate acceptable purchase contracts with EQT or third parties, (iv) we are unable to obtain financing for these acquisitions on economically acceptable terms, (v) we are outbid by competitors or (vi) we are unable to obtain necessary governmental or third-party consents, 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 and potential growth;

·    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;

·    the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

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

·    unforeseen difficulties operating in new geographic areas or business lines.

 

If any acquisition eventually proves not to be accretive to our distributable cash flow per unit, it could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

 

Expanding our business by constructing new midstream assets subjects us to risks.

 

Organic and greenfield growth projects, such as those described under “Business—Our Assets—Internal Growth Projects,” are a significant component of our growth strategy. The development and construction of pipelines and storage facilities involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. These types of projects may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new midstream asset, the construction will occur over an extended period of time, and we will not receive material increases in revenues until the project is placed into service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations and ability to make distributions.

 

Certain of our internal growth projects may require regulatory approval from federal and state authorities prior to construction, including any extensions from or additions to our transmission and storage system. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas, including the Marcellus Shale play. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.

 



 

The Sunrise Pipeline project is currently under construction and may not be completed on schedule, at the budgeted cost or at all. In addition, our ability to purchase the Sunrise Pipeline in the future is subject to a number of uncertainties, including the timing and receipt of governmental and third party approvals.

 

We believe the Sunrise Pipeline will be placed into service in the third quarter of 2012. The construction of the Sunrise Pipeline involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may not be completed on schedule, at the budgeted cost or at all.

 

After transfer of the Sunrise Pipeline, we will lease and operate the Sunrise Pipeline under a lease agreement with EQT that terminates after 15 years, unless terminated earlier at EQT’s sole discretion. Upon termination of the lease agreement, we will be required to purchase the Sunrise Pipeline at a price to be negotiated between the parties. For a description of this lease agreement, please read “Certain Relationships and Related Transactions—Contracts with Affiliates—Sunrise Pipeline Lease Agreement.” There can be no assurance that the acquisition of the Sunrise Pipeline will prove accretive to our distributable cash flow.

 

In addition there may be certain consents, orders, or approvals required from local, state, or federal authorities or other third parties involving the transfer and lease of the Sunrise Pipeline, the financing for the acquisition of the project, and the disposition of any land interests associated with the project. Although our growth strategy includes the acquisition of the Sunrise Pipeline, the parties may not be able to obtain all required governmental or third party approvals for such acquisition on schedule or at all.

 

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase. We do not have any commitment with any of our affiliates to provide any direct or indirect financial assistance to us following the closing of this offering.

 

In order to expand our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We will be required to use cash from our operations or incur borrowings or sell additional common units or other limited partner interests in order to fund our expansion capital expenditures. Using cash from operations will reduce cash available for distribution to our common unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the

 



 

then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

 

We do not have any commitment with our general partner or other affiliates, including EQT, to provide any direct or indirect financial assistance to us following the closing of this offering.

 

We are subject to numerous hazards and operational risks.

 

Our business operations are subject to all of the inherent hazards and risks normally incidental to the gathering, compressing, transportation and storage of natural gas. These operating risks include, but are not limited to:

 

·    damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

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

·    uncontrolled releases of natural gas and other hydrocarbons;

·    leaks, migrations or losses of natural gas as a result of the malfunction of equipment or facilities and, with respect to storage assets, as a result of undefined boundaries, geologic anomalies, natural pressure migration and wellbore migration;

·    ruptures, fires and explosions; and

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

 

These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. In spite of any precautions taken, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to provide reservations charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

 



 

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

 

We are not fully insured against all risks inherent to our businesses, including environmental accidents that might occur. In addition, we do not maintain business interruption insurance in the type and amount to cover all possible risks of loss. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

 

EQT currently maintains excess liability insurance that covers EQT’s and its affiliates’, including our, legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability but excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition; and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of EQT and its affiliates.

 

EQT also maintains coverage for itself and its affiliates, including us, for physical damage to assets and resulting business interruption, including damage caused by terrorist acts committed by a U.S. person or interest.

 

All of EQT’s insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates, and we may elect to self insure a portion of our asset portfolio. The insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. In addition, we share insurance coverage with EQT, for which we will reimburse EQT pursuant to the terms of the omnibus agreement. To the extent EQT experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased.

 

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

 

Our natural gas gathering, transportation and storage 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, known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties

 



 

currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;

·    the federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;

·    the federal Oil Pollution Act, or 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, or 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, or ESA; and

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

 

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. In addition, future changes in environmental or other laws may result in additional compliance expenditures that have not been pre-funded and which could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders. For example, on April 7, 2012, the EPA issued final rules that establish new air emission controls for oil and natural gas production, processing, transmission and storage operations. Specifically, EPA’s rule package includes standards to address emissions of sulfur dioxide and volatile organic compounds, or VOC, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish new or more stringent requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment in addition to leak detection requirements for natural gas processing plants. These rules may require modifications to certain of our operations, which could include the installation of new equipment to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely affect our business.

 

There is a risk that we may incur costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of wastes and potential emissions and discharges related to our operations. Private parties, including the owners

 



 

of the properties through which our transmission and storage system or our gathering system pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to require remediation of contamination or enforce compliance with environmental requirements as well as to seek damages 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. Pursuant to the terms of the omnibus agreement, EQT will indemnify us for certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets retained by us and occurring before the closing date of this offering. However, the maximum liability of EQT for these indemnification obligations will not exceed $15 million, which may not be sufficient to fully compensate us for such claims, losses and expenses. 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.

 

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

 

In December 2009, the EPA published its findings that emissions of greenhouse gases, or GHGs, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates GHG emissions from certain large stationary sources under the Clean Air Act Prevention of Significant Deterioration and Title V permitting programs. The stationary source rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA expanded its existing GHG emissions reporting rule to include onshore oil and natural gas processing, transmission, storage, and distribution activities, beginning in 2012 for emissions occurring in 2011. Congress has also from time to time considered legislation to reduce emissions of GHGs. The adoption of any legislation or regulations that restrict emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the natural gas we transport, store and gather.

 

Significant portions of our pipeline systems have been in service for several decades. 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.

 

Significant portions of our transmission and storage system and our gathering system have been in service for several decades. The age and condition of our systems could 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 systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

 

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and related repairs.

 

Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the U.S. Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could harm “high consequence areas,” including high population areas, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators, including us, to:

 

·    perform ongoing assessments of pipeline integrity;

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

·    maintain processes for data collection, integration and analysis;

·    repair and remediate pipelines as necessary; and

·    implement preventive and mitigating actions.

 

Moreover, changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. On January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which act, among other things, directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. These safety enhancement requirements and other provisions of this act could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our financial position or results of operations.

 

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 gathering pipelines. 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 retain approximately $32 million of the net proceeds from this offering in order to pre-fund certain identified regulatory compliance capital expenditures, the majority of which are expected to be incurred over the next two years; however the actual cost of such expenditures may exceed $32 million. Furthermore, we are not restricted from using this approximately $32 million for other purposes. In addition, we may be required to make additional maintenance capital expenditures in the future for similar regulatory compliance initiatives that are not reflected in our forcasted maintenance capital expenditures. For additional information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors and Trends Impacting our Business—Regulatory Compliance Capital Expenditures.”

 

The adoption of legislation relating to hydraulic fracturing and the enactment of severance taxes and impact fees on natural gas wells could cause our current and potential customers to reduce the number of wells they drill in the Marcellus Shale. If drilling reductions are significant, the reductions would have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

 

Our assets are primarily located in the Marcellus Shale fairway in southern Pennsylvania and northern West Virginia and a majority of the production that we receive from customers is produced from wells completed using hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Marcellus Shale. The EPA is developing permitting guidance under the federal Safe Drinking Water Act for hydraulic fracturing activities that use diesel fuels in fracturing fluids. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Any such legislation may provide more opportunities for third parties opposed to hydraulic fracturing to initiate legal proceedings against our customers. In addition, a number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with shale development, including hydraulic fracturing. On May 4, 2012, the Department of the Interior’s Bureau of Land Management, or BLM, issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed, which would then become publicly available, and includes provisions addressing well-bore integrity and flowback water management plans. Some industry commentators have predicted that similar rules will follow that will impose a national minimum standard on hydraulic fracturing activities. These additional regulatory burdens could make it more costly or uneconomical for our customers to develop wells, thereby limiting future oil and gas production and reducing future demand for our services. In addition, some states and municipalities have adopted, and other states and municipalities are considering adopting, regulations that could prohibit hydraulic fracturing in certain areas or impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. For example, Pennsylvania has adopted a variety of regulations since 2010 governing well drilling and hydraulic fracturing completion practices, including the adoption of upgraded well

 



 

construction and casing standards, upgraded cement standards and new recordkeeping requirements. Additionally, in 2012 Pennsylvania enacted legislation that authorizes counties to assess a local impact fee for unconventional gas wells, establishes additional regulatory requirements relating to horizontal drilling, and is intended to ensure uniformity between statewide environmental protection standards and municipal ordinances. Similarly, in 2011, West Virginia adopted legislation that establishes additional regulatory requirements relating to horizontal drilling and hydraulic fracturing. These initiatives could result in additional levels of regulation and permitting of hydraulic fracturing operations, which could cause our customers to experience operational delays, increased operating and compliance costs, restrictions or bans on drilling new wells, and additional regulatory burdens that could make it more difficult or commercially impracticable for our customers to perform hydraulic fracturing, delaying the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing and reducing the volume of natural gas transported through our pipelines.

 

The results of our operations are affected by natural gas drilling activity which in turn could be affected by the state tax burdens placed on gas production and drilling and completion operations. West Virginia imposes severance tax on oil and gas production. Pennsylvania does not impose a severance tax. In 2012, Pennsylvania enacted legislation authorizing counties to impose an annual impact fee on unconventional gas wells (generally defined as wells using hydraulic fracturing or multilateral well bores) for the first 15 years of each well’s life. Total fees per well over the 15-year term range from $190,000 to $355,000, depending on gas prices and subject to consumer price indexing.

 

The counties had sixty days or until April 16th to adopt the fee, and thirty-seven counties had chosen to opt for imposing the fee, as have fourteen counties who as of yet do not have any of these wells within their borders. As Pennsylvania counties adopt impact fees, growth in drilling and production in Pennsylvania could be reduced. If drilling reductions are significant, our operations could be adversely impacted.

 

We are exposed to costs associated with lost and unaccounted for volumes.

 

A certain amount of natural gas is naturally lost in connection with its transportation across a pipeline system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to run our compressor stations, which we refer to as fuel usage. The level of fuel usage and lost and unaccounted for volumes on our transmission and storage system and our gathering system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our contractual agreements and it will be necessary to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. For the years ended December 31, 2009, 2010 and 2011, our actual level of fuel usage and lost and unaccounted for volumes exceeded the amounts recovered from our gathering customers by approximately 300 BBtu, 1,500 BBtu and 1,300 BBtu, respectively and for which we recognized $2.0 million, $5.7 million and $4.9 million of purchased gas cost as a component of operating and maintenance expense in 2009, 2010 and 2011, respectively. Future exposure to the volatility of

 



 

natural gas prices as a result of gas imbalances could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

 

Our exposure to direct commodity price risk may increase in the future.

 

Although we intend to enter into fixed-fee contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges or other fixed fee arrangements and therefore have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of natural gas prices as a result of our future contracts could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

 

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

 

We do not own 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, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we might have to relocate our facilities. A loss of rights-of-way or a relocation could have a material adverse effect on our business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

 

Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our natural gas storage business.

 

Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, the demand for our storage services and the prices that we will be able to charge for those services may decline. For example, between 2010 and 2011 the natural gas commodity market pricing spreads between the summer and winter months decreased, resulting in a decrease in our parking service volumes and pricing, and accordingly we experienced a

 



 

decrease in storage operating revenues for the year ended December 31, 2011 as compared to the prior year.

 

In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated storage expansion activities. For instance, the settlement approved by the FERC in our most recent rate case included a provision allowing us to recover 7.1 Bcf of storage base gas through our transmission fuel retention percentage. To the extent we need to replace storage base gas in excess of 7.1 Bcf, we may not be able to recover the cost of acquiring such base gas from our customers and will be subject to commodity price risk. An extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition, results of operations and ability to make distributions.

 

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

 

Upon the closing of the offering, we will enter into a $350 million revolving credit facility. Our new credit facility will contain various covenants and restrictive provisions that will limit our ability to, among other things:

 

· incur or guarantee 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, sell or otherwise dispose of assets.

 

Our new credit facility also will contain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control and we cannot assure you that we will meet those ratios and tests. In addition, our credit facility will contain events of default customary for transactions of this nature, including the occurrence of a change of control (which will occur if EQT fails to own a majority of the equity interests of our general partner, we fail to own 100% of Equitrans, L.P., or our general partner fails to be our general partner).

 

The provisions of our new credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our new credit facility could result in an event of default, which could enable our lenders to, subject to the terms and conditions of the revolving credit facility, declare any 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. The new credit facility will also have cross default provisions that apply to any other indebtedness we may have with an

 



 

aggregate principal amount in excess of $15.0 million. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility.”

 

Our future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.

 

Following this offering, we will have the ability to incur debt, subject to limitations in our credit facility. Our 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 our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

 

The credit and risk profile of our general partner and its owner, EQT, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

 

The credit and business risk profiles of our general partner and EQT may be factors considered in credit evaluations of us. This is because our general partner, which is owned by EQT, controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in the financial condition of EQT, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, or a downgrade of EQT’s investment-grade credit rating, may adversely affect our credit ratings and risk profile.

 

If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner or EQT, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of EQT and its affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to

 



 

raise financing in the capital markets, which would impair our ability to grow our business and make distributions to common unitholders.

 

Increases in interest rates could adversely impact demand for our storage capacity, 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.

 

There is a financing cost for our customers to store natural gas in our storage facilities. That financing cost is impacted by the cost of capital or interest rate incurred by the customer in addition to the commodity cost of the natural gas in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.

 

In addition, 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.

 

The amount of cash we have available for distribution to unitholders 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.

 

The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.

 

We rely exclusively on revenues generated from transmission, storage and gathering systems that we own, which are exclusively located in the Appalachian Basin in Pennsylvania and West Virginia. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for natural gas, could have a significantly greater impact on our results of operations and cash available for distribution to our common unitholders than if we maintained more diverse assets and locations.

 



 

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

 

Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report, as described below) beginning with for our fiscal year ending December 31, 2013. 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. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls 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.

 

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.

 

In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act, or the JOBS Act. For as long as we remain an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our limited partner interests held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

 

In addition, the JOBS Act provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected to “opt out” of this exemption and, therefore, will be

 



 

subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

 

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile.

 

Terrorist attacks aimed at our facilities or surrounding areas could adversely affect our business.

 

The U.S. government has issued warnings that energy assets, specifically the nation’s pipeline and terminal infrastructure, may be the future targets of terrorist organizations. Any terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, refineries or terminals could materially and adversely affect our business, financial condition, results of operations or cash flows.

 

Risks Inherent in an Investment in Us

 

Our general partner and its affiliates, including EQT, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

 

Following this offering, EQT will indirectly own and control our general partner and will appoint all of the officers and directors of our general partner. All of our initial officers and a majority of our initial directors will also be officers and/or directors of EQT. Although our general partner has a 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 EQT. Conflicts of interest will arise between EQT 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 EQT 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 EQT to pursue a business strategy that favors us, and the directors and officers of EQT have a fiduciary duty to make these decisions in the best interests of EQT, which may be contrary to our interests. EQT may choose to shift the focus of its investment and growth to areas not served by our assets.

· EQT, as our primary customer, has an economic incentive to cause us not to seek higher tariff rates or gathering fees, even if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third party transaction.

· EQT is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them.

 



 

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

· All of the officers and a majority of the directors of our general partner are also officers and/or directors of EQT and will owe fiduciary duties to EQT. The officers of our general partner will also devote significant time to the business of EQT and will be compensated by EQT accordingly.

· Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such 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.

· Disputes may arise under our commercial agreements with EQT and its affiliates.

· 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 available for distribution 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 or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders 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 $30 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 or general partner units or to our general partner in respect of 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, including EQT’s obligations under the omnibus agreement and its commercial agreements with us.

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

· Our general partner may transfer its incentive distribution rights without unitholder

 



 

approval.

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

 

Please read “Conflicts of Interest and Duties.”

 

EQT and other affiliates of our general partner are not restricted in their ability to compete with us.

 

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner, including EQT and its other subsidiaries, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. EQT currently holds interests in, and may make investments in and purchases of, entities that acquire, own and operate other natural gas midstream assets. EQT will be under no obligation to make any acquisition opportunities available to us. Moreover, while EQT may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to accept any offer we might make with respect to such opportunity.

 

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and EQT. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders. Please read “Conflicts of Interest and Duties.”

 

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

 

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

 

In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To

 



 

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

 

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

 

Prior to this offering, there has been no public market for our common units. After this offering, there will be only 12,500,000 publicly traded common units, assuming no exercise of the underwriters’ over-allotment option. In addition, EQT will own 4,839,718 common units and 17,339,718 subordinated units, representing an aggregate of approximately 62.7% limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

 

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

 

· the level of our quarterly distributions;

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

· the loss of a large customer;

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

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

· general economic conditions;

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

· future sales of our common units; and

· other factors described in these “Risk Factors.”

 



 

You will experience immediate and substantial dilution in net tangible book value of $9.02 per common unit.

 

The initial public offering price of $21.00 per common unit exceeds our pro forma net tangible book value of $11.98 per unit. Based on the initial public offering price of $21.00 per common unit, you will incur immediate and substantial dilution of $9.02 per common unit. This dilution results primarily because the assets contributed by EQT are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”

 

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

 

We have been approved to list our common units on the NYSE, subject to official notice of issuance. Unlike most corporations, we are not required by NYSE rules to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or 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 taxable holder, you will not be entitled to allocations of income or loss or distributions or voting rights on your common units and your common units will be subject to redemption.

 

In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by FERC or analogous regulatory body, we have adopted certain requirements regarding those investors who may own our common units. Eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. Please read “Description of the Common Units—Transfer of Common Units.” If you are not a person who fits the requirements to be an eligible taxable holder, you will not receive allocations of income or loss or distributions or voting rights on your units and you run the risk of having your units redeemed by us at the market price calculated in accordance with our partnership agreement as of the date of redemption. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please see “The Partnership Agreement—Non-Citizen Assignees; Redemption.”

 

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

 

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. 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, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision 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;

· whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;

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

· whether to elect to reset target distribution levels;

· whether to transfer the incentive distribution rights or any units it owns to a third party; and

· whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.

 

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

 

Our partnership agreement restricts the remedies available to holders of our common 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, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, 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;

· 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;

 



 

· our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its 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

· our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

· 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;

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

· determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

· determined by the board of directors of our general partner to be 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 or the conflicts committee 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 the third and fourth bullets 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 challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

 

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

 

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including EQT, for expenses they incur and payments they make on our behalf. Under the omnibus agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses, which we project to be approximately $50 million, excluding reimbursements related to the Sunrise Pipeline lease, for the twelve-month period ending June 30, 2013. Please read “Certain Relationships and Related Transactions—Omnibus Agreement.” Our partnership

 



 

agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

 

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. Rather, the board of directors of our general partner will be appointed by EQT. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

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

 

Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates, including EQT, will own sufficient units upon the closing of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Following the closing of this offering, EQT will indirectly own 64.0% of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful 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 unitholder dissatisfaction with the performance of our general partner 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 EQT 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.

 

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of EQT selling or contributing additional midstream assets to us, as EQT would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

 

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, including limited partner interests that rank senior to the common units, 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;

· because the amount payable to holders of incentive distribution rights is based on a

 



 

percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

· 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.

 

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

 

After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, EQT will indirectly hold an aggregate of 4,839,718 common units and 17,339,718 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, we have agreed to provide EQT with certain registration rights. 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 intends to limit its liability regarding our obligations.

 

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, 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 general partner has a limited call right that may require you to sell your units at an undesirable time or price.

 

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the closing of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, EQT will indirectly own approximately 27.9% 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), EQT will indirectly own approximately 64.0% of our outstanding common units. For additional information about this right, please read “The Partnership Agreement—Limited Call Right.”

 



 

Our general partner, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

 

The holder or holders of a majority of the incentive distribution rights, which is initially our general partner, have the right, at any time when there are no subordinated units outstanding and the holders have received incentive distributions at the highest level to which they are entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and 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, 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. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions.

 

In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units rather than retain 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. This risk could be elevated if our incentive distribution rights have been transferred to a third party. 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. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

 



 

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

 

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

 

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

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

 

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

 

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

 

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

 

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

 

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure

 



 

controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements and our general partner will maintain director and officer liability insurance under a separate policy from EQT’s corporate director and officer insurance. We have included $3.0 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

 

Tax Risks to Common Unitholders

 

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

 

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

 

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

 

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

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (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 additional tax on us by a 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. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Please read “Material Federal Income Tax Consequences—Partnership Status.” We are unable to predict whether any of these changes or any other proposals will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

 

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

 

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

 



 

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

 

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

 

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

 

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

 

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

 

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

 



 

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

 

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

 

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

 

We will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Our counsel 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.