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As filed with the Securities and Exchange Commission on March 25, 2011
Registration No. 333-172797
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Amendment No. 1
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
ECA Marcellus Trust I
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)

1311
(Primary Standard Industrial Classification Code Number)

27-6522024
(I.R.S. Employer Identification No.)

919 Congress Avenue
Suite 500
Austin, Texas 78701
(512) 236-6599

(Address, including zip code, and telephone number,
including area code, of agent of service)
The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue
Suite 500
Austin, Texas 78701
(512) 236-6599
Attention: Michael J. Ulrich

(Name, address, including zip code, and telephone number,
including area code, of agent for service)


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

 
Copies to:
         
David P. Oelman
Vinson & Elkins L.L.P.
First City Tower
1001 Fannin Street, Suite 2500
Houston, Texas 77002-6760
(713) 758-2222
  Thomas W. Adkins
Bracewell & Giuliani LLP
111 Congress Avenue
Suite 2300
Austin, Texas 78701-4061
(512) 472-7800
  Joshua Davidson
Baker Botts L.L.P.
910 Louisiana St.
Houston, Texas 77002-4995
(713) 229-1234
 
     If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o
     If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
     If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
     If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer þ   Smaller reporting company o
        (Do not check if a smaller reporting company)    
 
CALCULATION OF REGISTRATION FEE
                             
 
              Proposed Maximum     Proposed Maximum     Amount of  
        Amount to be     Offering Price Per     Aggregate Offering     Registration  
  Title of Each Class of Securities to be Registered     Registered(1)     Unit     Price(1)(2)     Fee(3)  
 
Common Units
    3,001,733     $30.04     $90,172,060     $10,469  
 
 
(1)   Calculated in accordance with Rule 457(c) based on average high and low prices of a Common Unit as reported on the New York Stock Exchange on March 18, 2011.
 
(2)   Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
 
(3)   On March 14, 2011, in connection with the initial filing of this registration statement, the Trust paid an initial filing fee of $11,902.
     The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission (or the “SEC”), acting pursuant to said Section 8(a), may determine.
 
 

 


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The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities, and we are not soliciting an offer to buy these securities, in any jurisdiction where the offer or sale is not permitted.
SUBJECT TO COMPLETION DATED MARCH 25, 2011
PRELIMINARY PROSPECTUS
2,525,000 Common Units
Representing Beneficial Interests
ECA Marcellus Trust I
 
     All of the shares of common units offered by this prospectus are being sold by Energy Corporation of America (“ECA”). ECA Marcellus Trust I will not receive any of the proceeds from this offering.
     The trust’s common units are listed on the New York Stock Exchange under the symbol “ECT.” On March 24, 2011 the last reported sales price of the trust’s common units on the New York Stock Exchange was $31.83 per common unit.
     The Trust Units. Trust units, consisting of the common and subordinated units, are units of beneficial interest in the trust and represent undivided interests in the trust.
     The Trust. The trust owns term and perpetual royalty interests in natural gas properties owned by ECA in the Marcellus Shale formation in Greene County, Pennsylvania. These royalty interests entitle the trust to receive 90% of the proceeds attributable to ECA’s interest in the sale of production from 14 horizontal Marcellus Shale natural gas wells located in Greene County, Pennsylvania and 50% of the proceeds attributable to ECA’s interest in the sale of production from 52 horizontal Marcellus Shale natural gas development wells that have been or will be drilled on drill sites included within approximately 9,300 acres held by ECA, of which it owns substantially all of the working interests, in Greene County, Pennsylvania. Of these 52 horizontal Marcellus Shale natural gas development wells, 26.83 (calculated as provided in the Development Agreement) have been drilled as of February 28, 2011. The trust is treated as a partnership for federal income tax purposes.
     The Trust Unitholders. As a trust unitholder, you are entitled to receive quarterly distributions of cash from the proceeds that the trust receives from ECA’s sale of natural gas subject to the royalty interests held by the trust.
     ECA’s Right to Incentive Distributions. ECA is entitled to receive incentive distributions equal to 50% of the amount, if any, by which the cash available for distribution on all of the trust units in any quarter exceeds certain target distribution levels. ECA is entitled to reimbursement for approximately $5 million plus interest at 10% per annum in expenses incurred in connection with establishing floor price contracts transferred to the trust from the remaining 50% of cash available for distribution in excess of these thresholds. Please see “Target distributions and subordination and incentive thresholds.”
 
Investing in the common units involves a high degree of risk. Please read “Risk Factors” beginning on page 11 of this prospectus.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
 
                 
    Per Common Unit   Total
Public offering price
  $       $    
Underwriting discounts and commissions (1)
  $       $    
Proceeds to ECA (before expenses)
  $       $    
 
     The underwriters may also purchase up to an additional 360,723 common units from ECA at the initial public offering price, less underwriting discounts and commissions, to cover over-allotments, if any, within 30 days of the date of this prospectus. In connection with the closing of this offering, 116,010 common units are being conveyed by ECA to certain eligible employees. Please read “Underwriting — Employee Incentive Units”
 
Sole Book-Running Manager
Citi
     
  Co-Managers  
     
Oppenheimer & Co.   RBC Capital Markets
 
             , 2011

 


 

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Important Notice About Information in This Prospectus
     You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Until      , 2011 (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the common units, whether or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
     ECA and the trust have not authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. This prospectus is not an offer to sell or a solicitation of an offer to buy the common units in any jurisdiction where such offer and sale would be unlawful. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this document. The trust’s business, financial condition, results of operations and prospects may have changed since such dates.

 


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SUMMARY
     This summary provides a brief overview of information contained elsewhere in this prospectus. To understand this offering fully, you should read the entire prospectus carefully, including the risk factors included or incorporated by reference herein and the financial statements and notes to those statements. Definitions for terms relating to the natural gas business can be found in “Glossary of certain oil and natural gas terms and terms related to the trust.” Ryder Scott Company, L.P., an independent engineering firm, provided the estimates of proved natural gas reserves as of December 31, 2010 included in this prospectus. These estimates are contained in a summary prepared by Ryder Scott of its reserve report as of December 31, 2010 for the royalty interests held by the trust, which royalty interests are referred to herein as the “Royalties.” This summary is located at the back of this prospectus as Annex A and is referred to in this prospectus as the “reserve report.” References to “Energy Corporation of America” or “ECA” in this prospectus are to Energy Corporation of America and its subsidiaries. Unless otherwise indicated, all information in this prospectus assumes no exercise of the underwriters’ over-allotment option.
ECA MARCELLUS TRUST I
     ECA Marcellus Trust I is a statutory trust formed in March 2010 under the Delaware Statutory Trust Act, pursuant to a Trust Agreement (the “Trust Agreement”) among Energy Corporation of America, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The Trust owns royalty interests in 14 producing horizontal natural gas wells producing from the Marcellus Shale formation and located in Greene County, Pennsylvania (“Producing Wells”), and 52 horizontal natural gas development wells drilled or to be drilled to the Marcellus Shale formation (the “PUD Wells”) within the “Area of Mutual Interest,” or “AMI,” in which ECA presently holds approximately 9,300 acres, of which it owns substantially all of the working interests, in Greene County, Pennsylvania. As of February 28, 2011, ECA had drilled eight PUD Wells which were online and producing and an additional thirteen PUD Wells which were undergoing or awaiting completion (which is the equivalent of 26.83 wells, calculated as provided in the Development Agreement). The Area of Mutual Interest consists of the Marcellus Shale formation in approximately 121 square miles. At the closing of the initial public offering of the trust units, ECA granted the trust a lien on ECA’s interest in the Marcellus Shale formation in the AMI (exclusive of wells which were producing at that time) in order to secure its drilling obligation to the trust. ECA is obligated to drill the remaining PUD Wells from drill sites on approximately 9,300 leased acres in the AMI. Until ECA has satisfied its drilling obligation, it will not be permitted to drill and complete any well in the Marcellus Shale formation on lease acreage included within the AMI for its own account. The royalty interests were conveyed from ECA’s working interest in the Producing Wells and the PUD Wells limited to the Marcellus Shale formation (the “Underlying Properties”). The royalty interest in the Producing Wells (the “PDP Royalty Interest”) entitles the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells. The royalty interest in the PUD Wells (the “PUD Royalty Interest” and collectively, with the PDP Royalty Interest, the “Royalties”) entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells. Approximately 50% of the estimated natural gas production attributable to the Trust’s royalty interests has been hedged with a combination of floors and swaps through March 31, 2014. ECA is entitled to recoup its costs of establishing the floor price contracts only if and to the extent cash available for distribution by the Trust exceeds certain levels. Please see “Target distributions and subordination and incentive thresholds.”
     ECA is obligated to drill all 52 of the PUD Wells by March 31, 2013. However, in the event of delays, ECA will have until March 31, 2014 to fulfill its drilling obligation. ECA has granted the trust a lien on ECA’s interest in the Marcellus Shale Formation in the AMI (except the Producing Wells and any other wells which were already producing on the grant date) in order to secure the estimated amount of the drilling costs for the trust’s interests in the PUD Wells (the “Drilling Support Lien”). As of the grant date, the amount obtained by the trust pursuant to the Drilling Support Lien could not exceed $91 million. As ECA fulfills its drilling obligation over time, the total dollar amount that may be recovered will be proportionately reduced and the drilled PUD Wells will be released from the lien. As of December 31, 2010, the maximum amount of the Drilling Support Lien had been reduced to $74.1 million. However, after giving effect to the total number of wells drilled as of February 28, 2011 (26.83 wells, calculated as

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provided in the Development Agreement), the maximum amount of the Drilling Support Lien would be reduced to approximately $44.0 million.
     The trust is not responsible for any costs related to the drilling of development wells or any other development or operating costs. The trust’s cash receipts in respect of the Royalties are determined after deducting post-production costs and any applicable taxes associated with the Royalties, and the trust’s cash available for distribution includes cash receipts from its hedging contracts and are reduced by trust administrative expenses and expenses incurred as a result of being a publicly traded entity. Post-production costs generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production costs on its Greene County Gathering System is limited to $0.52 per MMBtu gathered until ECA has fulfilled its drilling obligation (the “Post-Production Services Fee”); thereafter, ECA may increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System.
     As of December 31, 2010, the total gas reserves estimated to be attributable to the trust interests were 102.4 Bcf. This amount includes 59.9 Bcf of proved undeveloped reserves and 42.5 Bcf of proved developed reserves.
     ECA’s retained interest in the Underlying Properties entitles it to 10% of the proceeds from the sale of natural gas from the Producing Wells as well as 50% of the proceeds from the sale of production from the PUD Wells. ECA on average owns an 81.53% net revenue interest in the Producing Wells. Please read “Description of the royalties ” below. ECA operates all of the Producing Wells and has agreed to operate not less than 90% of the PUD Wells during the subordination period as defined below. In addition, ECA has agreed to operate the gas properties to which the Royalties relate and to cause to be marketed natural gas produced from these properties in the same manner it would if such properties were not burdened by the Royalties.
     Generally, the percentage of production proceeds received by the trust with respect to a well equals the product of (i) the percentage of proceeds to which the trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) ECA’s net revenue interest in the well. ECA on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the trust is entitled to receive on average 73.37% of the proceeds of production from the Producing Wells. With respect to a PUD Well, the conveyance related to the PUD Royalty Interest provides that the proceeds from the PUD Wells are calculated on the basis that the underlying PUD Wells are burdened only by interests that in total would not exceed 12.5% of the revenues from such properties, regardless of whether the royalty interest owners are actually entitled to a greater percentage of revenues from such properties. As the applicable net revenue interest of a well is calculated by multiplying ECA’s percentage working interest in such well by the unburdened interest percentage (87.5%), assuming ECA owns a 100% working interest in a PUD Well, such well would have a minimum 87.5% net revenue interest. Accordingly, the trust would be entitled to 43.75% of the production proceeds from such well. To the extent ECA’s working interest in a PUD Well is less than 100%, the trust’s share of proceeds would be proportionately reduced. Pursuant to the Development Agreement, however, ECA will only satisfy its drilling obligation when it has drilled 52 equivalent wells. Therefore, any reduction in production proceeds attributable to a PUD Well caused by ECA having less than a 100% working interest in the well will be offset by the requirement to drill additional wells to achieve a total of 52 equivalent wells; provided, that ECA may be required to drill fewer gross development wells due to lateral length of any well or wells exceeding 2,500 feet.
     The trust expects to make quarterly cash distributions of substantially all of its cash receipts, after deducting trust administrative expenses and the costs incurred as a result of being a publicly traded entity and reserves therefor, on or about 60 days following the completion of each quarter through (and including) the quarter ending March 31, 2030 (the “Termination Date”). The first quarterly distribution was made on August 31, 2010 to record unitholders as of August 16, 2010. The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. At the Termination Date, 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will revert automatically to ECA. The remaining 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will be sold, and the net proceeds therefrom will be distributed pro rata to the unitholders soon after the Termination Date. ECA will have a right of first refusal to purchase the remaining 50% of the royalty interests at the Termination Date. Because payments to the trust will be generated by depleting assets and the trust has a finite

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life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent a return of your original investment.
     The business and affairs of the trust are managed by The Bank of New York Mellon Trust Company, N.A. as Trustee. Although ECA operates all of the Producing Wells and substantially all of the PUD Wells, ECA has no ability to manage or influence the management of the trust.
TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS
     Subordination and Incentive Thresholds
     ECA has calculated quarterly target levels of cash distributions for the life of the trust, such levels having been set forth in the initial prospectus used in the initial public offering (“Initial Prospectus”). The amount of the quarterly distributions may fluctuate from quarter to quarter, depending on the proceeds received by the trust, among other factors. While target distributions increase as ECA completes its drilling obligations and production attributable to the trust increases, over time these target distributions decline as a result of the depletion of the reserves. These target distributions do not represent the actual distributions you should expect to receive with respect to your common units. Rather, the trust has established the target distributions in part to calculate the subordination and incentive thresholds.
     In order to provide support for cash distributions on the common units, ECA subordinated 4,401,250 of the trust units it retained following the initial public offering, which constitute 25% of the outstanding trust units. While the subordinated units are entitled to receive pro rata distributions from the trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units which is no less than the applicable quarterly subordination threshold, if there is not sufficient cash to fund such a distribution on all trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. Each applicable quarterly subordination threshold is equal to 80% of the target distribution level for the corresponding quarter (each, a “subordination threshold”). In exchange for agreeing to subordinate these trust units, and in order to provide additional financial incentive to ECA to perform its drilling obligation and operations on the Underlying Properties in an efficient and cost-effective manner, ECA is entitled to receive incentive distributions (the “incentive distributions”) equal to 50% of the amount by which the cash available for distribution on all of the trust units in any quarter exceeds 150% of the subordination threshold for such quarter (which is 120% of the target distribution for such quarter) (each, an “incentive threshold”).
     ECA has incurred costs of approximately $5 million in establishing the floor price contracts being transferred to the trust. ECA is entitled to reimbursement for these expenditures, plus interest at 10% per annum, only if and to the extent distributions to trust unitholders would otherwise exceed the incentive threshold. This reimbursement is deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the trust unitholders. ECA’s right to receive the remaining 50% of such cash in the form of incentive distributions would not be affected.
     The subordinated units will automatically convert into common units on a one-for-one basis and ECA’s right to receive incentive distributions and to recoup the reimbursement amount will terminate, at the end of the fourth full calendar quarter following ECA’s satisfaction of its drilling obligation to the trust. Accordingly, ECA bears the risk that it will not be partially or fully reimbursed for the floor price contracts to be transferred to the trust. The Trust currently expects that ECA will complete its drilling obligation on or before March 31, 2013 and that, accordingly, the subordinated units will convert into common units on or before March 31, 2014. In the event of delays, it will have until March 31, 2014 under its contractual obligation to drill all the PUD Wells, in which event the subordinated units would convert into common units on or before March 31, 2015. The period during which the subordinated units are outstanding is referred to as the “subordination period.”
     The table below sets forth the target distributions and subordination and incentive thresholds for each calendar quarter through the first quarter of 2015.

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    Subordination     Target     Incentive  
Period   Threshold     Distribution(1)     Threshold  
            (per unit)          
2011:
                       
First Quarter
  $ 0.446     $ 0.558     $ 0.669  
Second Quarter
    0.451       0.564       0.676  
Third Quarter
    0.550       0.688       0.825  
Fourth Quarter
    0.565       0.706       0.847  
2012:
                       
First Quarter
    0.574       0.717       0.861  
Second Quarter
    0.602       0.752       0.903  
Third Quarter.
    0.624       0.780       0.937  
Fourth Quarter
    0.701       0.876       1.051  
2013:
                       
First Quarter
    0.756       0.945       1.135  
Second Quarter
    0.754       0.942       1.131  
Third Quarter
    0.701       0.876       1.052  
Fourth Quarter
    0.659       0.824       0.989  
2014:
                       
First Quarter
    0.610       0.763       0.915  
Second Quarter
    0.589       0.736       0.883  
Third Quarter
    0.571       0.713       0.856  
Fourth Quarter
    0.549       0.687       0.824  
2015:
                       
First Quarter
    0.519       0.649       0.779  
 
(1)   Target Distributions do not represent minimum quarterly distributions. There is no guarantee that the Trust will pay distributions at the target distribution level in any quarter.
     For additional information with respect to the subordination and incentive thresholds, please see “Target distributions and subordination and incentive thresholds” and “Description of the royalties.”
ENERGY CORPORATION OF AMERICA
     ECA is a privately held energy company engaged in the exploration, development, production, gathering, aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf Coast and Rocky Mountain regions in the United States and in New Zealand. ECA or its predecessors have owned and operated natural gas properties in the Appalachian Basin for more than 45 years, and ECA is one of the largest natural gas operators in the Appalachian Basin. ECA sells gas from its own wells as well as third-party wells to local gas distribution companies, industrial end users located in the Northeast, other gas marketing entities and into the spot market for gas delivered into interstate pipelines. ECA owns and operates approximately 5,000 miles of gathering lines and intrastate pipelines that are used in connection with its gas aggregation activities.
     ECA was formed in September 1992 as a Colorado corporation and subsequently reincorporated in West Virginia through a merger with ECA’s predecessor in June 1995. ECA’s predecessor began operating in the Appalachian Basin in 1963. ECA’s principal offices are located at 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237, and its telephone number is (303) 694-2667. ECA is required to deliver to the Trustee a statement of the computation of the proceeds for each computation period, as well as quarterly drilling and production results. ECA is not a reporting company and does not file periodic reports with the SEC. Therefore, as a trust unitholder, you do not have access to financial information of ECA.
The trust units do not represent interests in or obligations of ECA.
FORMATION TRANSACTIONS
     At the closing of the initial public offering on July 7, 2010, the following transactions, which are referred to as the “formation transactions,” occurred:
    ECA conveyed to a wholly owned subsidiary a term royalty interest entitling the holder of the interest to receive 45% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years

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      commencing on April 1, 2010 (the “Term PDP Royalty”) and a term royalty interest entitling such holder of the interest to receive 25% of the proceeds from the sale of the production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010 (the “Term PUD Royalty”) in exchange for a demand note in the principal amount of approximately $161 million. The Term PDP Royalty and the Term PUD Royalty are collectively referred to as the “Term Royalties.”
 
    ECA and the Private Investors conveyed to the trust perpetual royalty interests entitling the trust to receive, in the aggregate, 45% of the proceeds from the sale of production of natural gas attributable to the interests of ECA in the Producing Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PDP Royalty”) and a perpetual royalty interest entitling the trust to receive an additional 25% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PUD Royalty”) in exchange for, in the case of ECA, 3,087,371 common units constituting 17.5% of the trust units outstanding and 4,401,250 subordinated units constituting 25% of the trust units outstanding, and in the case of the Private Investors, 1,313,879 common units constituting 7.5% of the trust units outstanding. The Perpetual PDP Royalty and the Perpetual PUD Royalty are collectively referred to as the “Perpetual Royalties.”
 
    The trust sold 8,802,500 common units to the public, representing a 50.0% interest in the trust.
 
    ECA conveyed to the trust the natural gas floor price contracts and entered into a back-to-back swap agreement with the trust providing the trust with the benefit of the swap contracts entered into between ECA and third parties.
 
    ECA’s subsidiary conveyed the Term Royalties to the trust in exchange for a payment from the net proceeds from the initial public offering and used the net proceeds to repay all of the demand note to ECA and the remaining net proceeds were distributed to ECA.
 
    ECA purchased 209,312 common units from the Private Investors at the initial offering price.
 
    ECA and the trust entered into an Administrative Services Agreement outlining the provision of administrative services to the trust and its compensation therefor and a Development Agreement outlining ECA’s drilling obligation to the trust with respect to the PUD Wells. Please see “The Trust — Administrative Services Agreement and Development Agreement.”
 
    ECA granted to the trust the Drilling Support Lien.
 
    ECA granted to the trust a lien on the PDP Royalty Interest and the PUD Royalty Interest (the “Royalty Interest Lien”) to provide protection to the trust, in the event of a bankruptcy of ECA, against the risk that the Royalties were not considered a real property interest.
     On July 21, 2010, the Trust sold an additional 294,950 common units pursuant to the underwriters’ over-allotment option.

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KEY INVESTMENT CONSIDERATIONS
     The following are some key investment considerations related to the Royalties and the common units:
    Royalties not burdened by operating or capital costs. The trust is not responsible for any operating or capital costs associated with the Underlying Properties, including the costs to drill the PUD Wells. As a result, the trust’s burden to pay costs associated with any particular well will not arise until such well is producing natural gas attributable to the trust’s interest. The principal costs the trust will bear are the Post-Production Services Fee; property, ad valorem, production, severance, excise, franchise and similar taxes, if any; and trust administrative expenses including costs incurred as a result of being a publicly traded entity. In addition, the trust is obligated to reimburse ECA for approximately $5 million plus interest at 10% per annum incurred in establishing the floor price contracts transferred to the trust if and to the extent cash available for distribution by the trust exceeds certain levels.
 
    Downside protection against natural gas price volatility through natural gas hedging contracts for approximately 50% of estimated production through March 31, 2014. The trust has entered into swap hedging contracts covering approximately 50% of the expected production volumes attributable to the trust from April 1, 2010 through March 31, 2014. The swap contracts relate to approximately 7,500 MMBtu per day at a weighted average price of $6.78 per MMBtu for the period from April 1, 2010 through June 2012. The price of the floor price hedging contracts is $5.00 per MMBtu. These hedging contracts should reduce commodity price risks inherent in holding interests in natural gas through the end of March 31, 2014.
 
    Alignment of interests between ECA and the trust unitholders. ECA is significantly incentivized to complete its drilling obligation, to increase production from the Underlying Properties and to obtain the best prices for the natural gas production from the Underlying Properties as a result of the following factors:
    A portion of the trust units that ECA owns, constituting 25% of the outstanding trust units, are subordinated units that are not entitled to receive distributions unless there is sufficient cash to pay the subordination threshold to the common units. These subordinated units only convert into common units upon completion of the subordination period and are not being offered hereby.
 
    To the extent that the trust has cash available for distribution in excess of the incentive thresholds during the subordination period, ECA is entitled to receive 50% of such cash as incentive distributions and 50% of such cash as recoupment of its costs for establishing the floor price contracts until it has recouped approximately $5 million plus interest at 10% per annum.
 
    ECA is not be permitted to drill and complete any development wells in the Marcellus Shale formation on the lease acreage within the AMI for its own account or sell the Underlying Properties until it has satisfied its drilling obligation.
    Potential for initial depletion to be offset by results of development drilling. ECA is obligated to drill the PUD Wells by March 31, 2014. Furthermore, ECA is incentivized to increase production in the near term in order to receive incentive distributions. While production from the trust properties will decline in the long term, production from the PUD Wells is expected to offset depletion of the Producing Wells in the near term.
 
    ECA’s experience and position as Marcellus Shale operator. Since January 1, 2006, ECA has drilled over 180 Marcellus Shale wells throughout the Appalachian Basin and operates Marcellus Shale wells in New York, Pennsylvania and West Virginia. ECA was one of the earliest operators in the Marcellus Shale region, having drilled test wells in this play in the late 1970s in partnership with the U.S. Department of Energy, and on April 18, 2008, it drilled and completed the Consol USX-13 well, which was one of the first horizontal Marcellus Shale wells in Greene County, Pennsylvania. ECA has drilled 141 gross vertical development wells and 42 gross horizontal wells in the Marcellus Shale formation, and it has successfully completed 100% of these wells. ECA is currently the operator of all of the Producing Wells and has agreed to operate not less than 90% of the PUD Wells during the subordination period, allowing ECA to control

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      the timing and amount of discretionary expenditures for operational and development activities with respect to substantially all of the PUD Wells. ECA’s senior managers possess an average of 27.5 years of industry experience with an extensive focus on operations in the Appalachian Basin and Marcellus Shale.
 
    Experience of ECA marketing natural gas production. As the operator of all of the Producing Wells and substantially all the PUD Wells, ECA has the responsibility to market or cause to be marketed the natural gas production related to the Underlying Properties.
 
    Proximity of the Appalachian Basin to major markets. The Appalachian Basin is located close to a substantial number of large commercial and industrial gas markets, including natural gas powered electricity plants, and major residential markets in the northeastern United States. This proximity, together with the stable nature of Appalachian Basin production and the availability of transportation facilities, has resulted in generally higher realized prices for Appalachian Basin natural gas (including Marcellus Shale formation natural gas) than realized prices available in other regions of the United States.
KEY RISK FACTORS
     Trust Units are inherently different from the capital stock of a corporation, although many of the business risks to which the trust is subject are similar to those that would be faced by a corporation engaged in a similar business Below is a summary of certain key risk factors for consideration related to the Royalties and the common units. This list is not exhaustive, please also read carefully the full discussion of these risks and other risks described under “Risk factors” on page 11. Before you invest in trust units, you should carefully consider these risk factors. You should also consider all of the other information included in this prospectus and the other documents incorporated herein by reference in evaluating an investment in our common units.
    Drilling and completion of the PUD Wells are high risk activities with many uncertainties that could delay ECA’s anticipated drilling schedule and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease future revenues that are available for distribution to unitholders.
 
    Natural gas prices fluctuate due to a number of factors that are beyond the control of the Trust and ECA, and lower prices could reduce proceeds to the Trust and cash distributions to unitholders.
 
    Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the trust units.
 
    The generation of proceeds for distribution by the Trust depends in part on gathering, transportation and processing facilities owned by ECA and others. Any limitation in the availability of those facilities could interfere with sales of natural gas production from the Underlying Properties.
 
    Due to the Trust’s lack of industry and geographic diversification, adverse developments in the Trust’s existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.
 
    The natural gas reserves estimated to be attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and gas properties or royalty interests to replace the depleting assets and production.
 
    The amount of cash available for distribution by the Trust will be reduced by the amount of post-production costs, applicable taxes associated with the Trust’s interest, Trust expenses, incentive distributions and reimbursement obligations payable to ECA.

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    The ability of ECA to satisfy its obligations to the Trust depends on the financial position of ECA, and in the event of a default by ECA in its obligation to drill the PUD Wells, or in the event of ECA’s bankruptcy, it may be expensive and time-consuming for the Trust to exercise its remedies.
 
    Federal and state legislative and regulatory initiatives relating to hydraulic fracturing or drilling operations generally could result in increased costs and additional operating restrictions or delays as well as adversely affect ECA’s services.
    The Trust’s tax treatment depends on its status as a partnership for federal income tax purposes. If the IRS were to treat the Trust as a corporation for federal income tax purposes, then its cash available for distribution to you would be substantially reduced.
    If the Trust were subjected to a material amount of additional entity-level taxation by Pennsylvania or any other states, the Trust’s cash available for distribution to you would be reduced.
PROVED RESERVES
     Proved reserves of the Royalties. The following table sets forth certain estimated proved reserves, estimated future net cash flows and the discounted present value thereof attributable to the Royalties as of December 31, 2010, in each case derived from the reserve report. The reserve report was prepared by Ryder Scott in accordance with criteria established by the Securities and Exchange Commission, or “SEC.” In accordance with the SEC’s rules, the reserves presented below were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, without giving effect to the derivative transactions, and were held constant for the life of the properties. This yielded a price for natural gas of $4.65 per Mcf. Proved reserve quantities attributable to the Royalties are calculated by multiplying the gross reserves for each property less fuel usage and line loss by the royalty interest assigned to the Trust in each property. The net cash flows attributable to the trust’s reserves are net of the trust’s obligation to reimburse ECA for post-production costs. The reserves and cash flows attributable to the trust’s interests include only the reserves attributable to the Royalties that are expected to be produced within the 20-year period in which the trust owns the royalty interest as well as the 50% residual interest in the reserves that the trust will own on the Termination Date. A summary of the reserve report is included as Annex A to this prospectus.
                         
    Proved Gas     Estimated Future     Discounted Estimated  
Proved Reserves   Reserves (Bcf)     Net Cash Flows     Future Net Cash Flows (1)  
            (Dollars in thousands)          
Royalty Interests:
                       
Proved Developed (2)
    42.486     $ 174,607     $ 98,757  
Proved Undeveloped
    59.963       246,430       132,485  
 
                 
Total
    102.449     $ 421,037     $ 231,242  
 
                 
 
(1)   The present values of future net cash flows for the Royalties were determined using a discount rate of 10% per annum.
 
(2)   Includes reserves currently behind pipe in wells which are in the process of being completed.
     Annual production attributable to royalty interests. The following bar graph shows estimated annual production, as of December 20, 2010, from the Royalties based on the pricing and other assumptions set forth in the reserve report dated December 20, 2010. The production estimates include the impact of additional production that is as a result of the drilling of the PUD Wells. This chart is presented to show the anticipated decline curve on the Trust’s reserves. The target distributions and incentive thresholds were prepared based on the reserve report dated May 26, 2010, as a result the estimated annual production presented in this graph differs from the estimates used in establishing the target distributions and subordination and incentive thresholds set forth herein.
(BAR GRAPH)

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THE OFFERING
     
Common units offered to public
  2,525,000 units
 
2,885,723 common units if the underwriters exercise their over allotment option in full
 
   
Total units outstanding after the offering
  13,203,750 common units and 4,401,250 subordinated units
 
   
Use of proceeds
  The trust will not receive any of the proceeds from the sale of the common units by ECA
 
   
NYSE symbol
  “ECT”
 
   
Trustee
  The Bank of New York Mellon Trust Company, N.A.
 
   
Quarterly cash distributions
  Actual cash distributions to the trust unitholders will fluctuate quarterly based on the quantity of natural gas produced from the Underlying Properties, the prices received for natural gas production and other factors. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties initially increasing and subsequently diminishing over time, a portion of each distribution will represent a return of your original investment and the target distributions will decline over time. Production declines are expected to be offset in the near term by production realized from the drilling and successful completion of the PUD Wells.
 
   
 
  Quarterly cash distributions during the term of the trust will be made by the Trustee on or about the 60th day following the end of each calendar quarter to the trust unitholders of record on or about the 45th day following each calendar quarter.
 
   
Termination of the trust
  The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. The Term Royalties will automatically revert to ECA at the Termination Date, while the Perpetual Royalties will be sold and the proceeds thereof will be distributed to the unitholders at the Termination Date or soon thereafter. ECA will have a right of first refusal to purchase the Perpetual Royalties at the Termination Date.
 
   
Summary of income tax considerations
  The trust will be treated as a partnership for federal income tax purposes. Consequently, the trust will not incur any federal income tax liability. Instead, trust unitholders will be allocated an amount of the trust’s income, gain, loss, or deductions corresponding to their interest in the trust, which amounts may differ in timing or amount from actual distributions. The Term PDP Royalty will and the Term PUD Royalty should be treated as debt instruments for federal income tax purposes, and the trust will be required to treat a portion of each payment it receives with respect to each such royalty interest as interest income in accordance with the “noncontingent bond method” under the original issue discount rules contained in the Internal Revenue Code of 1986, as amended, and the corresponding regulations. The Perpetual PDP Royalty will and the Perpetual PUD Royalty should be treated as mineral royalty interests for federal income tax purposes, which generates ordinary income subject to depletion. Please read “Federal income tax considerations.”

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Estimated ratio of taxable income to distributions
  The Trust estimates that if you own units you purchase in this offering through the record date for distributions for the period ending December 31, 2013, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 65% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $2.50 per unit, the trust estimates that your average allocable federal taxable income per year will be no more than approximately $1.63 per unit. Please read “Federal income tax considerations.”

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RISK FACTORS
     Trust units are inherently different from the capital stock of a corporation, although many of the business risks to which the Trust is subject are similar to those that would be faced by a corporation engaged in a similar business. Before you invest in trust units, you should carefully consider the risk factors described below. You should also consider all of the other information included in this prospectus and the other documents incorporated herein by reference in evaluating an investment in the common units.
     If any of the risks discussed in the foregoing documents were actually to occur, the trust’s financial condition, results of operations, or cash flow could be materially adversely affected. In that case, the trust’s ability to make distributions to its trust unitholders may be reduced, the trading price of the trust units could decline and you could lose all or part of your investment.
     Drilling and completion of the PUD Wells are high risk activities with many uncertainties that could delay ECA’s anticipated drilling schedule and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease future revenues that are available for distribution to unitholders.
     The drilling and completion of the PUD Wells on the Underlying Properties are subject to numerous risks beyond ECA’s and the Trust’s control, including risks that could delay ECA’s current drilling schedule for the PUD Wells and the risk that drilling will not result in commercially viable natural gas production. ECA’s decisions to develop or otherwise exploit certain areas within the AMI will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. ECA’s costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, ECA’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including, but not limited to, the following:
    delays imposed by or resulting from compliance with regulatory requirements including permitting;
 
    unusual or unexpected geological formations;
 
    shortages of or delays in obtaining equipment and qualified personnel;
 
    equipment malfunctions, failures or accidents;
 
    lack of available gathering facilities or delays in construction of gathering facilities;
 
    lack of available capacity on interconnecting transmission pipelines;
 
    unexpected operational events and drilling conditions;
 
    pipe or cement failures;
 
    casing collapses;
 
    lost or damaged drilling and service tools;
 
    loss of drilling fluid circulation;
 
    uncontrollable flows of natural gas and fluids;
 
    fires and natural disasters;
 
    environmental hazards, such as natural gas leaks, pipeline ruptures and discharges of toxic gases;
 
    adverse weather conditions;
 
    reductions in natural gas prices;
 
    natural gas property title problems; and
 
    market limitations for natural gas.

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     In the event that drilling of development wells is delayed or development wells have lower than anticipated production due to one of the factors above or for any other reason, estimated future distributions to unitholders may be reduced.
     Natural gas prices fluctuate due to a number of factors that are beyond the control of the Trust and ECA, and lower prices could reduce proceeds to the Trust and cash distributions to unitholders.
     The Trust’s reserves and quarterly cash distributions are highly dependent upon the prices realized from the sale of natural gas. Natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and ECA. These factors include, among others:
    weather conditions and seasonal trends;
 
    regional, domestic and foreign supply and perceptions of supply of natural gas;
 
    availability of imported liquefied natural gas, or LNG;
 
    the level of demand and perceptions of demand for natural gas;
 
    anticipated future prices of natural gas, LNG and other commodities;
 
    technological advances affecting energy consumption and energy supply;
 
    U.S. and worldwide political and economic conditions;
 
    the price and availability of alternative fuels;
 
    the proximity, capacity, cost and availability of gathering and transportation facilities;
 
    the volatility and uncertainty of regional pricing differentials;
 
    acts of force majeure;
 
    governmental regulations and taxation; and
 
    energy conservation and environmental measures.
     Lower natural gas prices will reduce proceeds to which the Trust is entitled and may ultimately reduce the amount of natural gas that is economic to produce from the Underlying Properties. As a result, the operator of any of the Underlying Properties could determine during periods of low gas prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operator of the Underlying Properties could determine during periods of low gas prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, ECA may abandon any well or property if it reasonably believes that the well or property can no longer produce natural gas in commercially economic quantities. This could result in termination of the portion of the royalty interest relating to the abandoned well or property, and ECA would have no obligation to drill a replacement well. In making such decisions, ECA is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. As a result, the volatility of natural gas prices also reduces the accuracy of estimates of future cash distributions to Trust unitholders.
      Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the trust units.
     The value of the trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the reserves estimated to be attributable to the Trust’s royalty interests. The Trust’s reserve quantities and revenues are based on estimates of reserve quantities and revenues for the Trust. See “The Royalties—Natural gas reserves” of this prospectus for a discussion of the method of allocating proved reserves to the Trust. It is not possible to measure underground accumulations of natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary negatively and in material amounts from estimates and those variations could be material. Petroleum engineers are required to make subjective estimates of underground accumulations of natural gas based on factors and assumptions that include:

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    historical production from the area compared with production rates from other producing areas;
 
    natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and capital expenditures; and
 
    the assumed effect of governmental regulation.
     Changes in these assumptions or actual production costs incurred and results of actual development and production costs could materially decrease reserve estimates.
     In particular, reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in estimates of proved reserves, future production rates and the timing of development expenditures. The Producing Wells have been operational for approximately one year. Furthermore, the use of horizontal drilling methods on the Underlying Properties is a recent development in the Marcellus Shale, with ECA commencing the drilling of its first horizontal well in the Marcellus Shale in 2007. The lack of operational history for horizontal wells in the Marcellus Shale formation may also contribute to the inaccuracy of estimates of proved reserves. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates, including variances attributable to a lack of production history within the Marcellus Shale formation, would have a material adverse effect on the financial condition, results of operations and cash flows of the Trust and would reduce cash distributions to Trust unitholders.
     The generation of proceeds for distribution by the Trust depends in part on gathering, transportation and processing facilities owned by ECA and others. Any limitation in the availability of those facilities could interfere with sales of natural gas production from the Underlying Properties.
     The amount of natural gas that may be produced and sold from any well to which the Underlying Properties relate is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery of gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, ECA is provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If ECA is forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced due to the reduction of proceeds from the sale of production.
     Some of the wells on the underlying PUD properties will be drilled in locations that currently are not serviced by gathering and transportation pipelines or locations in which existing gathering and transportation pipelines do not have sufficient capacity to transport additional production. As a result, ECA may not be able to sell the natural gas production from certain PUD Wells until the necessary gathering systems and/or transportation pipelines are constructed or until the necessary transportation capacity on an interstate pipeline is obtained. Any delay in the construction or expansion of these gathering systems beyond the currently estimated construction schedules, or a delay in the procurement of additional transportation capacity would delay the receipt of any proceeds that may be associated with natural gas production from the PUD Wells. If transportation capacity is not available, either directly from a pipeline or pipelines or in the secondary capacity market, ECA would be required to request that the pipeline or pipelines construct additional facilities or expand their existing facilities to provide additional transportation capacity. The pipelines are not required to undertake such construction or expansion. If the pipeline refuses to construct additional transportation capacity or expand its existing transportation capacity, ECA may not be able to receive proceeds that may be associated with natural gas production from wells on the underlying PUD properties. Any delay in the construction or expansion of pipeline transportation facilities will delay the receipt of any proceeds that may be associated with natural gas production from wells on the underlying PUD properties.
     The generation of proceeds for distribution by the Trust depends in part on the ability of ECA and/or its customers to obtain service on transportation facilities owned by third party pipelines; any limitation in the availability of those facilities and/or any increase in the cost of service on those facilities could interfere with sales of natural gas production from the Underlying Properties.

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     Natural gas that is gathered on the Greene County Gathering System, including natural gas produced from the Underlying Properties, is currently shipped on two interstate natural gas transportation pipelines. ECA’s purchasers have contracted with those pipelines for firm or interruptible transportation service. The rates for service on the transportation pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) and are subject to increase if the pipeline demonstrates that the existing rates are unjust and unreasonable.
     ECA recently executed a binding precedent agreement with a third party to provide firm transportation downstream of ECA’s Greene County Gathering System for 50,000 Dth per day. This firm transportation arrangement is scheduled to be in service August 1, 2011 and will be at the third party’s filed tariff rate, which equates to $0.1996 per MMbtu at one hundred percent loadfactor. This is a post-production cost which will ensure downstream capacity and such costs will be charged to the Trust’s interest.
     ECA may, in the future, seek to obtain additional firm transportation capacity, but there can be no assurance that capacity will be available. In addition, to the extent ECA’s customers or ECA became dependent on interruptible service, and to the extent that either pipeline receives requests for service that exceed the capacity of the pipeline, the pipeline will honor requests by its firm customers first, and will then allocate remaining capacity, if any, to interruptible shippers. As a result, ECA or its customers may be unable to obtain all or a part of any requested interruptible capacity service on the transportation pipelines. Any inability of ECA or its customers to procure sufficient capacity to transport the natural gas gathered on its Greene County Gathering System will decrease and/or delay the receipt of any proceeds that may be associated with natural gas production from wells on the Underlying Properties. In addition, any increase in transportation rates paid by ECA for production attributable to the Trust’s interests will decrease the proceeds received by the Trust.
     Shortages or increases in costs of equipment, services and qualified personnel could delay the drilling of the PUD Wells and result in a reduction in the amount of cash available for distribution.
     The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly hinder ECA’s ability to perform the drilling obligations and delay completion of the development wells, which would reduce future distributions to Trust unitholders.
     Due to the Trust’s lack of industry and geographic diversification, adverse developments in the Trust’s existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.
     The Underlying Properties will be operated for natural gas production only and are focused exclusively in the Marcellus Shale formation in Greene County, Pennsylvania. In particular, the concentration of the Underlying Properties in the Marcellus Shale formation in Greene County, Pennsylvania could disproportionately expose the Trust’s interests to operational and regulatory risk in that area. Due to the lack of diversification in industry type and location of the Trust’s interests, adverse developments in the natural gas market or the area of the Underlying Properties could have a significantly greater impact on the Trust’s financial condition, results of operations and cash flows than if the Trust’s royalty interests were more diversified.
     The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.
     The existence of a material title deficiency with respect to the Underlying Properties can reduce the value or render a property worthless, thus adversely affecting the distributions to unitholders. ECA does not obtain title insurance covering mineral leaseholds. Additionally, undeveloped acreage has greater risk of title defects than developed acreage.
     Consistent with industry practice, ECA has not obtained preliminary title reviews on the PUD Wells that have not been drilled. Prior to the drilling of each new PUD Well, ECA intends to obtain a preliminary title review to ensure there are no obvious defects

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in title to the leasehold. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. ECA’s failure to cure any title defects may render some locations undrillable and cause ECA to lose its rights to production from the Underlying Properties. In the event of such a material title problem, proceeds available for distribution to unitholders and the value of the trust units may be reduced.
     The Trust is passive in nature and has no stockholder voting rights in ECA, managerial, contractual or other ability to influence ECA, or control over the field operations of, sale of natural gas from, or development of, the Underlying Properties.
     Trust unitholders have no voting rights with respect to ECA and therefore will have no managerial, contractual or other ability to influence ECA’s activities or operations of the gas properties. In addition, pursuant to the Administrative Services Agreement and the Development Agreement, up to 10% of the PUD Wells may be operated by third parties unrelated to ECA until completion of ECA’s drilling obligation, after which ECA may transfer operations of any or all of the Trust properties. Such third party operators may not have the operational expertise of ECA within the AMI. Gas properties are typically managed pursuant to an operating agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders has any contractual ability to influence or control the field operations of, sale of natural gas from, or future development of, the Underlying Properties. The trust units are a passive investment that entitle the Trust unitholder to only receive cash distributions from the royalty interests and hedging contracts that have been established for the benefit of the Trust.
     ECA may sell all or a portion of the Underlying Properties, subject to and burdened by the Royalties, after satisfying its drilling obligations to the Trust; any such purchaser could have a weaker financial position and/or be less experienced in natural gas development and production than ECA.
     Trust unitholders will not be entitled to vote on any sale of the Underlying Properties if the Underlying Properties are sold subject to and burdened by the Royalties and the Trust will not receive any proceeds from any such sale. The purchaser would be responsible for all of ECA’s obligations relating to the Royalties on the portion of the Underlying Properties sold, and ECA would have no continuing obligation to the Trust for those properties. Additionally, ECA may enter into farmout or joint venture arrangements with respect to the wells burdened by the Royalties. Any purchaser, farmout counterparty or joint venture partner could have a weaker financial position and/or be less experienced in natural gas development and production than ECA.
     The natural gas reserves estimated to be attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and gas properties or royalty interests to replace the depleting assets and production.
     The proceeds payable to the Trust from the Royalties are derived from the sale of the production of natural gas from the Underlying Properties. The natural gas reserves attributable to the Underlying Properties are depleting assets, which means that the reserves of natural gas attributable to the Underlying Properties will decline over time. As a result, the quantity of natural gas produced from the Underlying Properties will decline over time. Based on the estimated production volumes in the original reserve report described in the Initial Prospectus, the gas production from proved producing reserves attributable to the PDP Royalty Interest is projected to decline at an average rate of approximately 8.5% per year over the life of the Trust. As a PUD Well is drilled and placed on production, the production rate is expected to decline approximately 37.3% during the first year of production, approximately 14.7% during the next three to five years of production and approximately 8.0% per year for the remainder of the economically productive life of the well. These production characteristics are generally consistent with other development wells in the AMI. The anticipated rate of decline is an estimate and actual decline rates may vary from those estimated.
     Future maintenance may affect the quantity of proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these projects will depend on, among other factors, the market prices of natural gas. With the exception of ECA’s commitment to drill the PUD Wells, ECA has

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no contractual obligation to make capital expenditures on the Underlying Properties in the future. Furthermore, for properties on which ECA is not designated as the operator, ECA has no control over the timing or amount of those capital expenditures. ECA also has the right to non-consent and not participate in the capital expenditures on properties for which it is not the operator, in which case ECA and the Trust will not receive the production resulting from such capital expenditures. If ECA or other operators of the wells to which the Underlying Properties relate do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by ECA or estimated in the reserve report.
     The Trust Agreement provides that the Trust’s business activities are limited to owning the Royalties and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the Royalties. As a result, the Trust is not permitted to acquire other oil and gas properties or royalty interests to replace the depleting assets and production attributable to the Trust.
     The amount of cash available for distribution by the Trust will be reduced by the amount of post-production costs, applicable taxes associated with the Trust’s interest, Trust expenses, incentive distributions and reimbursement obligations payable to ECA.
     The Royalties and the Trust bear certain costs and expenses that reduce the amount of cash received by or available for distribution by the Trust to the holders of the trust units. These costs and expenses include those described below.
    Substantially all of the production from the Producing Wells and the PUD Wells utilize ECA’s Greene County Gathering System. The Trust pays the initial Post-Production Services Fee to ECA for use of such system, which includes ECA’s costs to gather, compress, transport, process, treat, dehydrate and market the gas. This fee is fixed until ECA’s obligation to drill the PUD Wells is satisfied; thereafter, ECA may increase this fee to the extent necessary to recover certain capital expenditures on the Greene County Gathering System, provided the resulting charge does not exceed the prevailing charges in the area for similar services. Additionally, the Trust is charged for the cost of fuel used in the compression process or equivalent electricity charges when electric compressors are used.
 
    Any third party post-production costs incurred in the future and associated with the Trust’s interests will reduce cash received by or available for distribution, including any amounts paid by ECA for transportation on downstream interstate pipelines. Such post-production costs will include the costs to be incurred in connection with the agreement ECA has recently entered into with a third party to obtain firm transportation downstream of ECA’s Greene County Gathering System for 50,000 Dth per day at the third party’s filed tariff rate, which equates to $0.1996 per MMbtu at one hundred percent loadfactor.
 
    Taxes allocated to or imposed on the Trust include Pennsylvania franchise tax and any applicable property, ad valorem, production, severance, excise and other similar taxes. Currently, there are no taxes in Pennsylvania related to the production or severance of oil and natural gas in Pennsylvania, but there are currently proposals pending in both the Pennsylvania Senate Finance and the House Energy and Environmental Resources Committees to enact a severance tax, and lawmakers may propose other taxes in the future. If adopted, such taxes would be a post-production cost that is borne by the Trust.
 
    The Trust bears 100% of Trust administrative expenses, including fees paid to the Trustee and the Delaware Trustee and an annual administrative services fee of $60,000 payable to ECA.
 
    The Trust is also responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees and registrar and transfer agent fees.
 
    ECA is entitled, during the subordination period, to receive a quarterly incentive distribution from the Trust in an amount equal to 50% of the amount by which distributions paid to all unitholders exceed the incentive thresholds described herein. A more detailed description of these

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      distributions is set forth under the caption “Target Distributions and Subordination and Incentive Thresholds” in this prospectus.
 
    ECA incurred costs of approximately $5 million in establishing the floor price contracts transferred to the Trust. ECA is entitled to recover the Reimbursement Amount only if and to the extent distributions to Trust unitholders would otherwise exceed the incentive threshold. This reimbursement will be deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the common and subordinated unitholders. ECA’s reimbursement right will terminate at the end of the subordination period.
     The amount of costs and expenses that will be borne by the Trust may vary materially from quarter-to-quarter. The extent by which the costs and expenses described above are higher or lower in any quarter will directly decrease or increase the amount received by the Trust and available for distribution to the unitholders. For a further summary of post-production costs and applicable taxes for the producing lives of the Producing Wells and PUD Wells, see “The Royalties—Marketing and Post-production services” of this prospectus. Historical post-production costs and taxes, however, may not be indicative of future post-production costs and taxes.
     A decrease in the differential between the price realized by ECA for natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of trust units.
     The prices received for ECA’s natural gas production usually exceed the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the price received and the benchmark price is called a basis differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors. ECA cannot accurately predict natural gas differentials. Decreases in the differential between the realized price of natural gas and the benchmark price for natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of the trust units.
     ECA has entered into natural gas floor price contracts for the benefit of the Trust and has entered into a back-to-back swap agreement with the Trust that cover only a portion of the estimated natural gas production attributable to the Royalties, and such hedging arrangements will terminate after March 31, 2014. The Trust’s receipt of any payments due based on these natural gas hedging contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the Trust unitholders.
     Fifty percent of the estimated natural gas production attributable to the Royalties is hedged through March 31, 2014. As a result, the remaining 50% of estimated production through March 31, 2014 and all production after such date will not be hedged to protect against the price risks inherent in holding interests in natural gas, a commodity that is frequently characterized by significant price volatility. Furthermore, while the use of hedging transactions limits the downside risk of price declines, swaps may also limit the Trust’s ability to realize cash flow from natural gas price increases on the portion of the production attributable to the Royalties that is hedged. The Trust will not have any ability to terminate the swaps before the expiration date.
     The Trust’s counterparties under the natural gas floor price contracts are Wells Fargo Foothill, Inc. and BP Energy Company, and its counterparty under the back-to-back swap agreement is ECA, whose counterparties are also Wells Fargo Foothill, Inc. and BP Energy Company. In the event that any of the counterparties to the natural gas hedging contracts default on their obligations to make payments to the Trust under the hedge contracts, the cash distributions to the Trust unitholders would likely be materially reduced as the hedge payments are intended to provide additional cash to the Trust during periods of lower natural gas prices. ECA has no continuing obligation with respect to the natural gas floor price contracts. However, ECA is the Trust’s counterparty under the back-to-back swap agreement and has continuing obligations with respect to this agreement.
     Natural gas wells are subject to operational hazards that can cause substantial losses. ECA maintains insurance; however, ECA may not be adequately insured for all such hazards.
     There are a variety of operating risks inherent in natural gas production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blow-outs, uncontrollable flow of natural gas,

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water or drilling fluids, casing collapses, abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of natural gas at any of the Underlying Properties will reduce Trust distributions by reducing the amount of proceeds available for distribution.
     Additionally, if any of such risks or similar accidents occur, ECA could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If ECA experiences any of these problems, its ability to conduct operations and perform its obligations to the Trust could be adversely affected. While ECA intends to obtain and maintain insurance coverage it deems appropriate for these risks with respect to the Underlying Properties, ECA’s operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance. If a well is damaged, ECA would have no obligation to drill a replacement well or make the Trust whole for the loss.
     The subordination of certain Trust units held by ECA does not assure that unitholders will in fact receive any specified return on an investment in the Trust.
     Although ECA will not be entitled to receive any distribution on its subordinated units unless there is enough cash for all of the common units to receive a distribution equal to the subordination threshold for such quarter (which is equal to 80% of the target distribution level for the corresponding quarter), the subordinated units constitute only a 25% interest in the Trust, and this feature does not guarantee that common units will receive a distribution equal to the subordination threshold, or any distribution at all. Additionally, the subordination period will terminate and the subordinated units will convert into common units four quarters following ECA’s completion of its drilling obligation. Depending on the prices at which ECA is able to sell volumes attributable to the Trust, the common units may receive a distribution that is below the subordination threshold.
     Actual cash distributions may differ materially from the target distributions due to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties.
     The target distributions subordination thresholds and incentive thresholds, as set forth in the Initial Prospectus under the caption “Target Distributions and Subordination and Incentive Thresholds,” are based on ECA’s calculations, and ECA has not received an opinion or report on such calculations from any independent accountants. Such calculations, as established and set forth in the Initial Prospectus, were based on assumptions about drilling, production, natural gas prices, hedging activities, capital expenditures, expenses, and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. In particular, these estimates have assumed that natural gas production is sold at prices consistent with settled NYMEX pricing for April, May and June 2010 of $3.842, $4.271 and $4.155 per MMBtu, respectively, and NYMEX forward pricing as of June 4, 2010 for the thirty three month period ending March 31, 2013 and increased thereafter by a 2.5% annual escalator (as adjusted for a basis differential of $0.15 per MMBtu escalated at 2.5% annually starting in the second quarter of 2013), capped at $9.00 per MMBtu starting in 2027; however, actual sales prices may be significantly lower. Additionally, these estimates assume that the PUD Wells will be drilled on ECA’s current anticipated schedule and the related Underlying Properties will achieve production volumes set forth in the reserve report; however, the drilling of the PUD Wells may be delayed and actual production volumes may be significantly lower. As a result, actual distributions may differ materially from the target distributions.
     Furthermore, the subordination thresholds for each quarter during the subordination period do not represent distributions you should expect to receive. To the extent actual cash distributions differ materially from those set forth in the estimates underlying target distributions, the actual distributions you receive may be lower than the target distribution and the subordination threshold for the applicable quarter. A cash distribution to Trust unitholders below the target distribution amount or the subordination threshold may materially adversely affect the market price of the trust units.
     The Trustee may, under certain circumstances, sell the Royalties and dissolve the Trust. The Trust will begin to terminate following the end of the 20-year period in which the Trust owns the Term Royalties.

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     The Trustee must sell the Royalties if unitholders approve the sale or vote to dissolve the Trust. The Trustee must also sell the Royalties if the gross proceeds to the Trust attributable to the Royalties and hedge agreements (after deducting any amounts owed to ECA pursuant to the natural gas swap agreements) are less than $1.5 million for any four consecutive quarters. Sale of all the Royalties will result in the dissolution of the Trust. The net proceeds of any such sale will be distributed to the Trust unitholders. The Trust will begin to liquidate on the Termination Date. The Trust unitholders will not be entitled to receive any proceeds from the sale of production from the Underlying Properties following such date. The Term Royalties will automatically revert to ECA at the Termination Date, while the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders (including ECA to the extent of any trust units it owns) at the Termination Date or soon thereafter. ECA will have a right of first refusal to purchase the Perpetual Royalties at the Termination Date. A more detailed description of this right of first refusal is set forth in this prospectus under the caption “The Trust.”
     Conflicts of interest could arise between ECA and the Trust unitholders.
     As a working interest owner in the Underlying Properties, ECA could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:
    Notwithstanding its drilling obligation to the Trust, ECA’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. Additionally, ECA may abandon a well which is uneconomic to it while such well is still generating revenue for the Trust unitholders. Subsequent to fulfilling its drilling obligation, ECA may make decisions with respect to expenditures and decisions to allocate resources on projects in other areas that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future. In making such decisions, ECA is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property.
 
    ECA may sell some or all of the Underlying Properties, subject to its obligation not to sell any of the underlying PUD properties prior to satisfying its obligation to drill the PUD Wells. Such sale may not be in the best interests of the Trust unitholders. Any purchaser may lack ECA’s experience in the Marcellus Shale or its credit worthiness.
 
    ECA may, without the consent of the Trust unitholders, require the Trust to release royalty interests with an aggregate value to the Trust of up to $5.0 million during any 12-month period. These releases will be made only in connection with the sale by ECA of the Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such royalty interests. See “The Royalties—Sale and Abandonment of Underlying Properties” in this prospectus.
 
    After it has completed its drilling obligation, ECA may in its discretion increase its Post-Production Services Fee for post-production costs on its Greene County Gathering System to the extent necessary to recover certain capital expenditures on the Greene County Gathering System.
 
    ECA is permitted under the conveyance agreements creating the Royalties to enter into new processing and transportation contracts without obtaining bids from or otherwise negotiating with any independent third parties, and ECA will deduct from the Trust’s proceeds any charges under

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      such contracts attributable to production from the Trust properties. Provisions in the conveyance agreements, however, require that charges under future contracts with affiliates of ECA relating to processing or transportation of natural gas must be comparable to charges prevailing in the area for similar services.
 
    ECA has registration rights and can sell its units without considering the effects such sale may have on common unit prices or on the Trust itself. Additionally, ECA can vote its trust units in its sole discretion.
     The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
     The business and affairs of the Trust are managed by the Trustee. Your voting rights as a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust Agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the outstanding trust units, including trust units held by ECA, at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding trust units. As a result, it will be difficult for public unitholders to remove or replace the Trustee without the cooperation of ECA (so long as it holds a significant percentage of total trust units) or other holders of a substantial percentage of the outstanding trust units.
     Trust unitholders have limited ability to enforce provisions of the Royalties, and ECA’s liability to the Trust is limited.
     The Trust Agreement permits the Trustee and the Trust to sue ECA or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the PDP and PUD Royalty Interests. If the Trustee does not take appropriate action to enforce provisions of these conveyances, Trust unitholders’ recourse would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust Agreement expressly limits a Trust unitholder’s ability to directly sue ECA or any other third party other than the Trustee. As a result, Trust unitholders will not be able to sue ECA or any future owner of the Underlying Properties to enforce these rights. Furthermore, the royalty interest conveyances provide that, except as set forth in the conveyances, ECA will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good faith.
     Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
     Under the Delaware Statutory Trust Act, Trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of corporations under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
     ECA is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose ECA to significant liabilities.
     ECA’s natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these laws and regulations, ECA must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. ECA may incur substantial costs in order to maintain compliance with these existing laws and regulations. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of natural gas and fluids as a result of drilling activities in the Marcellus Shale, there has been a variety of regulatory initiatives at the federal and state level to restrict oil and gas drilling operations in certain locations. Any increased regulation or suspension of oil and gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on ECA’s business, financial condition and results of operations. ECA must also comply with laws and regulations prohibiting fraud and market manipulations in energy

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markets. To the extent ECA is a shipper on interstate pipelines, it must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.
     Laws and regulations governing natural gas exploration and production may also affect production levels. ECA is required to comply with federal and state laws and regulations governing conservation matters, including provisions related to the unitization or pooling of the natural gas properties; the establishment of maximum rates of production from natural gas wells; the spacing of wells; the plugging and abandonment of wells; and removal of related production equipment. These and other laws and regulations can limit the amount of natural gas ECA can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.
     New laws or regulations, or changes to existing laws or regulations may unfavorably impact ECA, could result in increased operating costs and have a material adverse effect on ECA’s financial condition and results of operations. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in natural gas and oil exploration and production activities to, among other items the elimination of most U.S. federal tax incentives and deductions available to natural gas exploration and production activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. Additionally, the Pennsylvania Environmental Quality Board recently finalized in 2011 amendments to Pennsylvania’s oil and gas regulations to update existing requirements regarding the drilling, casing, cementing, testing, monitoring and plugging of oil and gas wells, and the protection of water supplies, including reporting the list of chemicals used in hydraulic fracturing or to stimulate the well. In addition, these regulations specify response actions that must be taken in the event of a report of gas migration from a well bore. These regulations could lead to significantly increased production costs and could otherwise impede operations.
     Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of ECA and third party downstream natural gas transporters. These and other potential regulations could increase ECA’s operating costs, reduce ECA’s liquidity, delay ECA’s operations, increase direct and third party post production costs associated with the Trust’s interests or otherwise alter the way ECA conducts its business, which could have a material adverse effect on ECA’s financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid by ECA for transportation on downstream interstate pipelines.
     The ability of ECA to satisfy its obligations to the Trust depends on the financial position of ECA, and in the event of a default by ECA in its obligation to drill the PUD Wells, or in the event of ECA’s bankruptcy, it may be expensive and time-consuming for the Trust to exercise its remedies.
     ECA is a privately held, independent energy company engaged in the exploration, development, production, gathering and aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf Coast and Rocky Mountain regions in the United States and in New Zealand. Pursuant to the terms of the Development Agreement, ECA is obligated to drill the PUD Wells at its own expense. ECA is also the operator of all of the Producing Wells and has agreed to operate substantially all of the PUD Wells until completion of its drilling obligation. The conveyances also provide that ECA is obligated to market, or cause to be marketed, the natural gas production related to the Underlying Properties. Additionally, ECA is the counterparty to the Trust’s swap agreement and has continuing obligations with respect to this agreement. Due to the Trust’s reliance on ECA to fulfill these numerous obligations, the value of the Royalties and its ultimate cash available for distribution will be highly dependent on ECA’s performance. ECA is not a reporting company and does not file periodic reports with the SEC. Therefore, as a Trust unitholder, you do not have access to financial information of ECA.
     The ability of ECA to perform these obligations will depend on ECA’s future financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for natural gas and oil, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of ECA.
     In the event that ECA defaults on its obligation to drill the PUD Wells, the Trust’s remedy would be to foreclose on the Trust’s Drilling Support Lien on all of ECA’s remaining interests in the AMI to recover the security interest in the amount of $91 million, which amount will be reduced proportionately as each PUD Well is drilled. As of December 31, 2010, the maximum amount of the Drilling Support Lien had been reduced to $74.1 million. However, after giving effect to the total number of wells drilled as of February 28, 2011 (26.83 wells, calculated as

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provided in the Development Agreement), the maximum amount of the Drilling Support Lien would be reduced to approximately $44.0 million. The process of foreclosing on such collateral may be expensive and time-consuming and delay the drilling and completion of the PUD Wells; such delays and expenses would reduce Trust distributions by reducing the amount of proceeds available for distribution. The amount of the security interest recovered is required to be applied to completion of the drilling obligations of ECA, will not result in any distribution to the Trust unitholders and may be insufficient to drill the number of wells needed for the Trust to realize the full value of the PUD Royalty Interest. Furthermore, the Trust would have to seek a new party to perform the drilling and operations of the wells. The Trust may not be able to find a replacement driller or operator, and it may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time.
     Due to uncertainty under the laws of Pennsylvania, there is a risk that the Royalties conveyed by ECA to the Trust would not be treated as real property interests, or interests in hydrocarbons in place or to be produced. As a result, the Royalties might be treated as unsecured claims of the Trust against ECA in the event of ECA’s bankruptcy. The Royalty Interest Lien is intended to provide security to the Trust should the Royalties be subject to such a challenge. If the PDP Royalty Interest or the PUD Royalty Interest were determined not to be a real property interest owned by the Trust, the Trust’s remedy would be to foreclose on the Trust’s Royalty Interest Lien to cause the Trust to receive a volume of natural gas production from the Trust properties calculated in accordance with the provisions of the conveyances of the Royalties to the Trust. Foreclosure on the Royalty Interest Lien is exercisable only following a bankruptcy filing of ECA or its successor and based on an uncured payment default occurring under the conveyances of the Royalties to the Trust existing at the time of, or occurring after, such bankruptcy filing. Similar to the Drilling Support Lien, the process of foreclosing to enforce the Royalty Interest Lien may be expensive and time-consuming; and the resulting delays and expenses would reduce Trust distributions by reducing the amount of proceeds available for distribution.
     The proceeds of the Royalties may be commingled, for a period of time, with proceeds of ECA’s retained interest. It is possible that the Trust may not have adequate facts to trace its entitlement to funds in the commingled pool of funds and that other persons may, in asserting claims against ECA’s retained interest, be able to assert claims to the proceeds that should be delivered to the Trust. In addition, during a bankruptcy of ECA, it is possible that payments of the royalties may be delayed or deferred. It is also possible that the obligation to pay royalties will be disaffirmed or cancelled. In either situation, the Trust may need to look to the Royalty Interest Lien to replace its rights under the Royalties. During the pendency of ECA’s bankruptcy proceedings, the Trust’s ability to foreclose on the Drilling Support Lien or the Royalty Interest Lien, and the ability to collect cash payments from customers being held in ECA’s accounts that are attributable to production from the Trust properties, may be stayed by the bankruptcy court. Delay in realizing on the collateral for the Drilling Support Lien and the Royalty Interest Lien is possible, and it cannot be guaranteed that a bankruptcy court would permit such foreclosure. It is possible that the bankruptcy would also delay the execution of a new agreement with another driller or operator. If the Trust enters into a new agreement with a drilling or operating partner, the new partner might not achieve the same levels of production or sell natural gas at the same prices as ECA was able to achieve.
     The operations of ECA are subject to environmental laws and regulations that may result in significant costs and liabilities.
     The natural gas exploration and production operations of ECA in the Marcellus Shale are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to ECA’s operations including the acquisition of a permit before conducting drilling; water withdrawal or waste disposal activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of ECA’s operations.
     There is inherent risk of incurring significant environmental costs and liabilities in the performance of ECA’s operations due to its handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater

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discharges related to its operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, ECA could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether ECA was responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which ECA’s wells are drilled and facilities where ECA’s petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage or to recover some or all of the costs of the removal or remediation of released materials. In addition, the risk of accidental spills or releases could expose ECA to significant liabilities that could have a material adverse effect on its financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require ECA to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition. ECA may not be able to recover some or any of these costs from insurance. As a result of the increased cost of compliance, ECA may decide to discontinue drilling. Additionally, permitting delays may inhibit ECA’s ability to drill the PUD Wells on schedule.
     Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas that ECA produces while the physical effects of climate change could disrupt ECA’s production and cause ECA to incur significant costs in preparing for or responding to those effects.
     On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment. These findings allow the agency to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs, effective January 2, 2011. This stationary source rule “tailors” these permitting programs to apply to certain stationary sources in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that will be established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also issued regulations that require the establishment and reporting of an inventory of GHG emissions from specified stationary sources, including certain onshore oil and natural gas exploration, development and production facilities. In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any laws or regulations imposing reporting obligations on, or otherwise limiting emissions of GHGs from, ECA’s equipment and operations could require ECA to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas that it produces. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on ECA’s assets and operations.
     Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect ECA’s services.
     Hydraulic fracturing is an important and commonly used process for the completion of natural gas wells, and to a lesser extent, oil wells, in formations with low permeabilities, such as shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s

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Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study expected to be available in late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. In addition, legislation was introduced in the recently completed 111th Session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and such legislation could be introduced and adopted in the current session of Congress. Also, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. For instance, the New York Department of Environmental Conservation announced in 2010 that the watersheds relied upon by New York City and Syracuse as sources of drinking water would be excluded from the pending generic environmental review process, thereby requiring natural gas operators seeking to drill in either of the watersheds, which are located in the Marcellus Shale region, to pursue a case-by-case environmental review to establish whether appropriate measures to mitigate potential impacts can be developed. The Pennsylvania Environmental Quality Board recently finalized in 2011 amendments to Pennsylvania’s oil and gas regulations to require, among other things, additional information in the stimulation record including water source identification and volume as well as a list of chemicals used to stimulate the well, including chemicals used in hydraulic fracturing. These amendments also affected requirements on drilling, casing, cementing, testing, monitoring, and plugging of oil and gas wells and specify response actions that must be taken in the event of a report of gas migration from a well bore. Moreover, in 2010, the Pennsylvania Department of Environmental Protection adopted a permitting policy concerning surface water discharges from wastewater treatment facilities handling flowback fluids and produced waters from oil and gas well sites that could result in increased requirements for treatment of these fluids and limitations on their discharge to receiving waters. The adoption of any federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process or associated disposal of hydraulic fracturing flowback fluids and produced waters (which fluids and waters may contain naturally-occurring radioactive constituents) could make it more difficult for ECA to complete natural gas wells in the Marcellus Shale as well as increase its costs of compliance and doing business. Moreover, if ECA is unable to remove and dispose of water at a reasonable cost and within applicable environmental rules, ECA’s ability to produce gas commercially and in commercial quantities from the Underlying Properties could be impaired.
Tax Risks Related to the Trust’s Common Units
     The Trust’s tax treatment depends on its status as a partnership for United States federal income tax purposes. At the inception of the Trust, the Trust received an opinion from tax counsel that the Trust will be treated as a partnership for United States federal income tax purposes. If the Internal Revenue Service were to treat the Trust as a corporation for United States federal income tax purposes, then its cash available for distribution to you would be substantially reduced.
     The anticipated after-tax economic benefit of an investment in the trust units depends largely on the Trust being treated as a partnership for federal income tax purposes. At the inception of the Trust, ECA and the Trust received an opinion from tax counsel that the Trust will be treated as a partnership for United States federal income tax purposes. In order for the Trust to be treated as a partnership for United States federal income tax purposes, current law requires that 90% or more of the Trust’s gross income for every taxable year consist of “qualifying income,” as defined in Section 7704 of the Internal Revenue Code. The Trust may not meet this requirement or current law may change so as to cause, in either event, the Trust to be treated as a corporation for United States federal income tax purposes or otherwise subject the Trust to taxation as an entity. Although the Trust does not believe based upon its current activities that it is so treated, a change in current law could cause it to be treated as a corporation for federal income tax purposes or otherwise subject it to taxation as an entity. The Trust has not requested, and does not plan to request, a ruling from the Internal Revenue Service, which we referred to as the IRS, on this or any other tax matter affecting it.
     If the Trust was treated as a corporation for federal income tax purposes, it would pay United States federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely be required to pay state income tax. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon the Trust as a corporation, its cash available for distribution to you would be substantially reduced. Therefore, treatment of the Trust as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of the trust units.

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     The Trust Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to taxation as a corporation or otherwise subjects it to entity-level taxation for United States federal income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law on the Trust.
     If the Trust were subjected to a material amount of additional entity-level taxation by Pennsylvania or any other states, the Trust’s cash available for distribution to you would be reduced.
     The Trust will be required to pay Pennsylvania franchise tax on its capital stock value, as determined pursuant to statute and apportioned to Pennsylvania. The current tax rate of 0.289% is currently scheduled to be reduced to 0.189% in 2012 and 0.089% in 2013 and to be completely phased out in 2014. This schedule may be altered and the taxes left in place subject to the General Assembly in its annual budget process. Changes in current state law may subject the Trust to additional entity-level taxation by Pennsylvania or other states. Because of widespread state budget deficits and other concerns, several states are evaluating the imposition of entity-level income, franchise, gross receipts, and similar taxes on entities taxed as partnerships for federal income tax purposes. Imposition of any additional taxes on the Trust may substantially reduce the cash available for distribution to you and, therefore, negatively impact the value of an investment in the trust units.
     The Trust Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to additional amounts of entity-level taxation for state or local income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law on the Trust.
     Recently proposed severance taxes in Pennsylvania could, if enacted, materially increase the applicable taxes that are borne by the Trust.
     Although Pennsylvania has historically not imposed a severance tax on the production of natural gas, the Pennsylvania House and Senate recently introduced similar bills that would impose a severance tax of 5% of the value of natural gas at the wellhead plus $0.046 per thousand feet of natural gas severed. The Pennsylvania House has introduced an additional bill that would impose severance tax of $0.30 per thousand cubic feet of natural gas severed. If this legislation or any future severance tax legislation is adopted, any such severance tax would be a cost that would be borne by the Trust and could materially reduce distributions to unitholders.
     The Trust Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to additional amounts of entity-level taxation for state or local income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law on the Trust.
     The tax treatment of publicly traded partnerships or an investment in our trust units could be affected by recent and potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
     The current United States federal income tax treatment of publicly traded partnerships, including the Trust, or an investment in the Trust units, may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress previously considered substantive changes to the existing United States federal income tax laws that affect certain publicly traded partnerships. Any modification to the United States federal income tax laws or interpretations thereof could make it difficult or impossible to meet the requirements for the Trust to be treated as a partnership for United States federal income tax purposes, affect or cause us to change our business activities, affect the tax considerations of an investment in the Trust, change the character or treatment of portions of the Trust income and adversely affect an investment in the Trust’s units. Moreover, any modification to the United States federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the previously proposed legislation would not appear to have affected the Trust’s tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any potential change in law or interpretation thereof could negatively impact the value of an investment in the trust units.
     Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate

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applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
     The recently enacted Patient Protection and Affordable Care Act of 2010, as amended by the Health Care and Education Reconciliation Act of 2010, is scheduled to impose a 3.8% Medicare tax on certain net investment income from a variety of sources earned by individuals for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a Trust unitholder’s allocable share of the Trust income and gain realized by a Trust unitholder from a sale of the trust units. The tax will be imposed on the lesser of (i) the Trust unitholder’s net income from all investments, or (ii) the amount by which the trust unitholder’s adjusted gross income exceeds $250,000 (if the Trust unitholder is married and filing jointly) or $200,000 (if the Trust unitholder is unmarried).
     The Trust prorates items of income, gain, loss and deduction between transferors and transferees of the Trust units each month based upon the ownership of the trust units on the first day of each month, instead of on the basis of the date a particular unit is transferred.
     The Trust prorates items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust 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, and, accordingly, the Trust’s counsel was unable to opine as to the validity of this method. 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 the trust unitholders. If the IRS contests the federal income tax positions the Trust takes, the market for the trust units may be adversely impacted, the cost of any IRS contest will reduce the Trust’s cash available for distribution to you and items of income, gain, loss and deduction may be reallocated among trust unitholders.
     If the IRS contests the federal income tax positions the Trust takes, the market for the Trust units may be adversely impacted and the cost of any IRS contest will reduce the Trust’s cash available for distribution to you.
     The Trust has not requested a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes or any other matter affecting the Trust. The IRS may adopt positions that differ from the conclusions of the Trust’s counsel expressed in this prospectus or from the positions the Trust takes. It may be necessary to resort to administrative or court proceedings to attempt to sustain some or all of the conclusions of the Trust’s counsel or the positions the Trust takes. A court may not agree with some or all of the conclusions of the Trust’s counsel or positions the Trust takes. Any contest with the IRS may materially and adversely impact the market for the trust units and the price at which they trade. In addition, the Trust’s costs of any contest with the IRS will be borne indirectly by the Trust unitholders because the costs will reduce the Trust’s cash available for distribution.
     You will be required to pay taxes on your share of the Trust’s income even if you do not receive any cash distributions from the Trust.
     Because the Trust unitholders will be treated as partners to whom the Trust will allocate taxable income which could be different in amount than the cash the Trust distributes, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of the Trust’s taxable income even if you receive no cash distributions from the Trust. You may not receive cash distributions from the Trust equal to your share of the Trust’s taxable income or even equal to the actual tax liability that results from that income.
     Tax gain or loss on the disposition of the trust units could be more or less than expected.
     If you sell your trust units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those trust units. Because distributions in excess of your allocable share of the Trust’s net taxable income decrease your tax basis in your trust units, the amount, if any, of such prior excess distributions with respect to the trust units you sell will, in effect, become taxable income to you if you sell such trust units at a price greater than your tax basis in those trust units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion recapture.

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     Tax-exempt entities and non-U.S. persons face unique tax issues from owning the Trust units that may result in adverse tax consequences to them.
     Investment in Trust units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, some of the Trust income allocated to organizations exempt from United States federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income which would be taxable to them. Distributions to non-U.S. persons may be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons may be required to file U.S. federal income tax returns and pay tax on their share of the Trust’s taxable income.
     The Trust will treat each purchaser of Trust units as having the same economic attributes without regard to the actual trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of the trust units.
     Due to a number of factors, including the Trust’s inability to match transferors and transferees of trust units, the Trust will adopt 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. It also could affect the timing of these tax benefits or the amount of gain from your sale of trust units and could have a negative impact on the value of the trust units or result in audit adjustments to your tax returns.
     A Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having disposed of those trust units. If so, he would no longer be treated for tax purposes as a partner with respect to those trust units during the period of the loan and may recognize gain or loss from the disposition.
     Because a Trust unitholder whose trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of the loaned Trust units, the trust unitholder may no longer be treated for United States federal income tax purposes as a partner with respect to those trust 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 the Trust’s income, gain, loss or deduction with respect to those trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those trust units could be fully taxable as ordinary income. The Trust’s counsel has not rendered an opinion regarding the treatment of a unitholder where trust units are loaned to a short seller to cover a short sale of trust units; therefore, trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their trust units.
     The Trust will adopt certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the trust unitholders. The IRS may challenge this treatment, which could adversely affect the value of the trust units.
     The federal income tax consequences of the ownership and disposition of trust units will depend in part on the Trust’s estimates of the relative fair market values, and the initial tax bases of the Trust’s assets. Although the Trust may from time to time consult with professional appraisers regarding valuation matters, the Trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by trust unitholders might change, and trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments. It also could affect the amount of gain from unitholders’ sale of trust units and could have a negative impact on the value of the trust units or result in audit adjustments to unitholders’ tax returns without the benefit of additional deductions.
     The sale or exchange of 50% or more of the Trust’s capital and profits interests during any twelve-month period will result in the termination of the Trust’s partnership status for federal income tax purposes.
     The Trust will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a twelve-month period. For purposes

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of determining whether the 50% threshold has been met, multiple sales of the same Trust unit within any 12 month period will be counted only once. The Trust’s termination would, among other things, result in the closing of its taxable year for all Trust unitholders, which would result in the Trust filing two tax returns (and the Trust unitholders could receive two Schedules K-1) for one calendar year. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs. In the case of a unitholder reporting on a taxable year other than a calendar year ending December 31, the closing of the Trust’s taxable year may also result in more than twelve months of the Trust’s taxable income being includable in his taxable income for the year of termination. A technical termination would not affect the Trust’s classification as a partnership for federal income tax purposes, but instead, the Trust would be treated as a new partnership for tax purposes. If treated as a new partnership, the Trust must make new tax elections and could be subject to penalties if the Trust is unable to determine that a technical termination occurred.
     Certain federal income tax preferences currently available with respect to natural gas production may be eliminated as a result of future legislation.
     Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2012 (the “2012 Budget”) is the elimination of certain key U.S. federal income tax preferences relating to natural gas exploration and production. The 2012 Budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources effective in 2012. Specifically, the 2012 Budget proposes to repeal the deduction for percentage depletion with respect to oil and natural gas wells, including interests such as the Perpetual Royalty Interests, in which case only cost depletion would be available.

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FORWARD-LOOKING STATEMENTS
     This prospectus contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and the Private Securities Litigation Reform Act of 1995 about the trust and other matters affecting an investment in the common units that are subject to risks and uncertainties. All statements other than statements of historical fact included in this document, including, without limitation, statements under “Summary” and “Risk factors” regarding the financial position, business strategy, production and reserve growth, and the activities of the trust are forward-looking statements.
     Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Forward-looking statements are subject to risks and uncertainties and include statements made in this prospectus under “Target distributions and subordination and incentive thresholds,” statements pertaining to future development activities and costs, and other statements in this prospectus that are prospective and constitute forward-looking statements.
     When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this document, could affect the future results of the energy industry in general, and ECA and the trust in particular, and could cause those results to differ materially from those expressed in such forward-looking statements:
    risks incident to the drilling and operation of natural gas wells;
 
    future production and development costs;
 
    the effect of existing and future laws and regulatory actions;
 
    the effect of changes in commodity prices, the ability of the trust’s hedge counterparties, including ECA, to meet their contractual obligations and conditions in the capital markets;
 
    competition from others in the energy industry; and
 
    uncertainty of estimates of natural gas reserves and production.
     This prospectus describes other important factors that could cause actual results to differ materially from expectations of ECA and the trust, including under the heading “Risk factors.” All written and oral forward-looking statements attributable to ECA or the trust or persons acting on behalf of ECA or the trust are expressly qualified in their entirety by such factors.

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USE OF PROCEEDS
     The trust will not receive any of the proceeds from the sale of the common units by ECA.
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
     The trust’s common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “ECT.” The last reported sale price of the common units on the NYSE on March 24, 2011 was $31.83. As of March 24, 2011, there were 17 holders of record of the common units.
                                         
                    Distributions              
    Unit Price     Per Common              
Quarter Ended   High     Low     Unit     Record Date     Payment Date  
March 31, 2011 (through March 24, 2011)
  $ 31.98     $ 25.50     $ (1 )     (1 )     (1 )
December 31, 2010
  $ 27.24     $ 20.16     $ 0.500     February 14, 2011     February 28, 2011  
September 30, 2010
  $ 20.47     $ 19.55     $ 0.421     November 15, 2010     November 30, 2010  
June 30, 2010
  $     $     $ 0.272 (2)   August 16, 2010     August 31, 2010  
 
(1)   The distributions attributable to the quarter ending March 31, 2011 have not yet been declared or paid.
 
(2)   These distributions were in excess of the target distributions for such quarters and as a result ECA received incentive distributions.

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ENERGY CORPORATION OF AMERICA
     ECA is a privately held energy company engaged in the exploration, development, production, gathering, aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf Coast and Rocky Mountain regions in the United States and in New Zealand. ECA or its predecessors have owned and operated natural gas properties in the Appalachian Basin for more than 45 years, and ECA is one of the largest natural gas operators in the Appalachian Basin. ECA sells gas from its own wells as well as third-party wells to local gas distribution companies, industrial end users located in the Northeast, other gas marketing entities and into the spot market for gas delivered into interstate pipelines. ECA owns and operates approximately 5,000 miles of gathering lines and intrastate pipelines that are used in connection with its gas aggregation activities.
     Substantially all of the production subject to the Royalties is gathered by ECA’s Greene County Gathering System. This system currently accesses two separate interconnects with the Texas Eastern Transmission, L.P. and Columbia Gas Transmission, L.L.C. interstate pipeline systems and includes nine (9) compressors (with 13,295 total horsepower) together with associated processing equipment. ECA’s interconnect agreements with these interstate pipelines currently allow it to deliver at the interconnections between ECA’s facilities and the interstate pipelines up to a total of 105,000 MMBtu per day for transportation by the interstate pipelines to ECA’s customers (approximately 46,000 MMBtu per day is currently being utilized), which is in excess of its current and expected volumes from the Underlying Properties. To the extent necessary, ECA will add additional compression and related facilities to this system at no cost to the trust, other than potential increases to the Post-Production Service fee to the extent necessary to recover certain capital expenditures after drilling is complete.
     ECA was formed in September 1992 as a Colorado corporation and subsequently reincorporated in West Virginia through a merger in June 1995. ECA’s predecessor began operating in the Appalachian Basin in 1963. ECA’s principal offices are located at 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237, and its telephone number is (303) 694-2667. ECA is not a reporting company and does not file periodic reports with the SEC. Therefore, as a trust unitholder, you will not have access to the financial information of ECA.
The trust units do not represent interests in or obligations of ECA.
BENEFICIAL OWNERSHIP OF ECA MARCELLUS TRUST I
     The following table sets forth certain information regarding the trust unit ownership of the trust by each person known to be the beneficial owner of more than 5% of the outstanding trust units.
             
    Beneficial Ownership
    Trust Units
    Trust Units   Percent
Energy Corporation of America
  7,402,983 (1)     42.1 %
 
(1)   Includes 3,001,733 Common Units and 4,401,250 Subordinated Units.

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THE TRUST
     The trust is a statutory trust created under the Delaware Statutory Trust Act in March 2010. The business and affairs of the trust is managed by The Bank of New York Mellon Trust Company, N.A., as Trustee. Although ECA operates all of the Producing Wells and substantially all of the PUD Wells, ECA has no ability to manage or influence the management of the trust. In addition, the Corporation Trust Company acts as Delaware Trustee of the trust. The Delaware Trustee has only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act.
     In connection with the formation of the trust and its initial public offering, ECA conveyed to a wholly owned subsidiary the Term PDP Royalty, which entitles the holder of the interest to receive 45% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010 and the Term PUD Royalty, which entitles such holder of the interest to receive 25% of the proceeds from the sale of the production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010 in exchange for a demand note in the principal amount of approximately $161 million.
     In connection with the formation of the trust and its initial public offering, ECA and the Private Investors conveyed to the trust the Perpetual PDP Royalty, which entitles the trust to receive, in the aggregate, 45% of the proceeds from the sale of production of natural gas attributable to the interests of ECA in the Producing Wells (after deducting post-production costs and any applicable taxes) and ECA conveyed to the trust the Perpetual PUD Royalty, which entitles the trust to receive an additional 25% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) in exchange for an aggregate 4,401,250 common units constituting 25% of the trust units outstanding and 4,401,250 subordinated units constituting 25% of the trust units outstanding.
     In connection with the formation of the trust and its initial public offering, ECA’s subsidiary conveyed the Term Royalties to the trust in exchange for the net proceeds from the initial public offering, after deducting underwriting commissions and discounts and expenses, and used the net proceeds to repay all or a portion of the demand note to ECA.
     The Trustee can authorize the trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the trust. The Trustee may authorize the trust to borrow from the Trustee as a lender provided the terms of the loan are fair to the trust unitholders. The Trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the trust at least equals amounts paid by the Trustee on similar deposits, and make other short term investments with the funds distributed to the trust. The Trustee may also hold funds awaiting distribution in a non interest bearing account.
     The trust is responsible for paying all legal, accounting, tax advisory, engineering, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the Trustee or the Delaware Trustee. The trust is also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees and registrar and transfer agent fees. For the year ended December 31, 2010, the trust’s administrative expenses were approximately $1.0 million which includes fees associated with the trust formation and initial public offering. The Trustee’s annual administrative fee is $150,000 and may be adjusted beginning on the fifth anniversary of the trust as provided in the trust agreement. The Delaware Trustee’s annual administrative fee is $2,400. These costs as well as those to be paid to ECA pursuant to the Administrative Services Agreement outlined below under “— Administrative services agreement and development agreement,” are deducted by the trust before distributions are made to trust unitholders.
     The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. The Term Royalties will automatically revert to ECA at the Termination Date, while the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders at the Termination Date or soon thereafter.

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     ECA has a right of first refusal to purchase the Perpetual Royalties at the Termination Date. This right of first refusal provides that the Trustee will use commercially reasonable efforts to retain a third-party advisor to market the Perpetual Royalties within 30 business days of the Termination Date. If the Trustee receives a bid from a proposed purchaser other than ECA and wants to sell all or part of the Perpetual Royalties, it will be required to give notice (the “Offer Notice”) to ECA, identifying the proposed purchaser and setting forth the proposed sale price, payment terms and other material terms under which the Trustee is proposing to sell. ECA would then have 30 days from receipt of the Offer Notice to elect, by notice to the Trustee, to purchase the subject properties offered for sale on the terms and conditions set forth in the Offer Notice. If ECA makes such election, the proposed purchaser would be entitled to receive reimbursement of its reasonable and documented expenses incurred in connection with its review and analysis of the subject properties and bid preparation. ECA and the trust would share equally the cost of reimbursement to the proposed purchaser.
     If ECA does not give notice within the 30-day period following the Offer Notice, the Trustee may sell such properties to the identified purchaser on terms and conditions that are substantially the same as those previously set forth in such Offer Notice.
     If, after a reasonable marketing period, no bid is received on any or all of the Perpetual Royalties from any party other than ECA, then ECA shall obtain, at the trust’s expense, and deliver to the Trustee, a fairness opinion from a nationally-recognized valuation firm with expertise in fairness opinions stating that the proposed sale price to be paid by ECA to the trust for the properties is fair to the trust.
ADMINISTRATIVE SERVICES AGREEMENT AND DEVELOPMENT AGREEMENT
     In connection with the closing of the initial public offering on July 7, 2010, the trust entered into an Administrative Services Agreement with ECA that obligates the trust to pay ECA each quarter an administrative services fee for accounting, bookkeeping and informational services to be performed by ECA on behalf of the trust relating to the royalty interests. The annual fee, payable in equal quarterly installments, totals $60,000. After the completion of ECA’s drilling obligation, subject to certain restrictions, ECA and the Trustee each may terminate the provisions of the Administrative Services Agreement relating to the providing by ECA of administrative services at any time following delivery of notice no less than 90 days prior to the date of termination.
     The Development Agreement obligates ECA to drill all of the PUD Wells by March 31, 2013. In the event of delays, ECA will have until March 31, 2014 under the Development Agreement to fulfill its drilling obligation. ECA granted to the trust a lien on ECA’s interest in the Marcellus Shale formation in the AMI (except the Producing Wells and any other wells which were already producing at the time of grant and not subject to the Royalties) in order to secure the estimated amount of the drilling costs for the trust’s interests in the PUD Wells (the “Drilling Support Lien”). As of the grant date, the amount obtained by the trust pursuant to the Drilling Support Lien could not exceed $91 million. As ECA fulfills its drilling obligation over time, the total dollar amount that may be recovered will be proportionately reduced and the completed PUD Wells will be released from the lien. As of December 31, 2010, the maximum amount of the Drilling Support Lien had been reduced to $74.1 million. However, after giving effect to the total number of wells drilled as of February 28, 2011 (26.83 wells, calculated as provided in the Development Agreement), the maximum amount of the Drilling Support Lien would be reduced to approximately $44.0 million.
     For purposes of ECA’s drilling obligation, and subject to the following paragraph, ECA will be credited with a full development well drilled if its working interest in the development well drilled is 100%. In the event that ECA’s working interest in a development well drilled is less than 100%, ECA will be credited with a portion of a development well in the proportion that its working interest in the development well bears to 100%. For example, if ECA’s working interest in a development well drilled by ECA in connection with fulfilling its drilling obligation to the trust is 50%, ECA will be credited with one-half of a development well for purposes of satisfying its drilling obligation in the period the development well was drilled. As a result, ECA may be required to drill more than the 52 Marcellus Shale natural gas development wells, in the aggregate, if ECA’s interest in any development well is less than 100%; provided, that ECA may be required to drill fewer gross development wells due to lateral length of any well or wells exceeding 2,500 feet.
     Wells drilled horizontally in the Marcellus Shale formation with a horizontal lateral distance (measured from the midpoint of the curve to the end of the lateral) of less than 2,500 feet will count as a fractional well in proportion to total lateral length divided by 2,500 feet. In the event ECA commences drilling of a PUD Well, but fails to drill

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beyond the mid-point of the curve, such well will not count as a fractional well. Wells with a horizontal lateral distance of greater than 2,500 feet (subject to a maximum of 3,500 feet) will count as one well plus a fractional well equal to the length drilled in excess of 2,500 (up to 3,500 feet) feet divided by 2,500 feet. Among the drilled wells, the average lateral length completed has been approximately 3,700 feet, with some wells extending beyond the average with a maximum lateral length drilled of 5,195 feet.
     ECA is obligated to bear all of the costs of drilling and completing the PUD Wells. ECA is required to complete and equip each development well that reasonably appears to ECA to be capable of producing gas in quantities sufficient to pay completion, equipping and operating costs. In making such decisions, ECA is required to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. See “The royalties — Sale and abandonment of underlying properties.”
     ECA covenanted and agreed not to drill and complete, and will not permit any other person within its control to drill and complete, any well in the Marcellus Shale formation on lease acreage included within the AMI for its own account until such time as ECA has met its commitment to drill the PUD Wells. Once ECA has completed its drilling obligation, the Trustee will be required to release the Drilling Support Lien in full. Upon the Trustee’s release of the Drilling Support Lien, ECA will further agree not to drill and complete, and will not permit any other person within its control to drill and complete, any well on the lease acreage that will have a perforated segment that will be within 500 feet of any perforated interval of a PUD Well or Producing Well in the Marcellus Shale formation.

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TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS
     ECA created the royalty interests through conveyances to the trust of royalty interests carved from their working interests in specified gas properties in Pennsylvania. The PDP Royalty Interest entitles the trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells for a period of 20 years commencing on April 1, 2010 and 45% thereafter. The PUD Royalty Interest entitles the trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of future production of natural gas attributable to ECA’s interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter.
     The amount of trust revenues and cash distributions to trust unitholders will depend on:
    the timing of initial production from the PUD Wells;
 
    natural gas prices received;
 
    the volume and Btu rating of natural gas produced and sold;
 
    post-production costs and any applicable taxes;
 
    the reimbursement by the trust, if any, of ECA’s costs associated with establishing the floor price contracts to be transferred to the trust; and
 
    administrative expenses of the trust and expenses incurred as a result of being a publicly traded entity.
     ECA has calculated quarterly target levels of cash distributions for the life of the trust, such levels having been set forth in the Initial Prospectus. The amount of the quarterly distributions may fluctuate from quarter to quarter, depending on the proceeds received by the trust, among other factors. While target distributions increase as ECA completes its drilling obligations and production attributable to the trust increases, over time these target distributions decline as a result of the depletion of the reserves. These “target distributions” do not represent the actual distributions you should expect to receive with respect to your common units. Rather, the trust has established the target distributions in part to calculate the subordination and incentive thresholds described in more detail below.
     In order to provide support for cash distributions on the common units, ECA subordinated 4,401,250 of the trust units it retained following the formation of the trust and the initial public offering, which constitutes 25% of the outstanding trust units. While the subordinated units are entitled to receive pro rata distributions from the trust if and to the extent there is sufficient cash to provide a cash distribution on the common units which is no less than the applicable quarterly subordination threshold, if there is not sufficient cash to fund such a distribution on all trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. Each applicable quarterly subordination threshold is equal to 80% of the target distribution level for the corresponding quarter. In exchange for subordinating these trust units, and in order to provide additional financial incentive to ECA to perform its drilling obligation and operations on the Underlying Properties in an efficient and cost-effective manner, ECA is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the trust units in any quarter exceeds 150% of the subordination threshold for such quarter (which is 120% of the target distribution for such quarter). ECA’s right to receive the incentive distributions will terminate upon the expiration of the subordination period.
     ECA has incurred costs of approximately $5.0 million in establishing the floor price contracts which were transferred to the trust at the closing of the trust’s initial public offering. ECA is entitled to reimbursement for these expenditures plus interest accrued at 10% per annum (the “Reimbursement Amount”) only if and to the extent distributions to trust unitholders would otherwise exceed the incentive threshold. This reimbursement is deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the trust unitholders.
     The subordinated units automatically convert into common units on a one-for-one basis and ECA’s right to receive incentive distributions and to recoup the reimbursement amount will terminate, at the end of the fourth full calendar quarter following ECA’s satisfaction of its drilling obligation to the trust. Accordingly, ECA bears the risk that it will not be partially or fully reimbursed for the hedging contracts it has established for the benefit of the trust.

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The trust currently expects that ECA will complete its drilling obligation on or before March 31, 2013 and that, accordingly, the subordinated units would convert into common units on or before March 31, 2014. In the event of delays, ECA will have until March 31, 2014 under the Development Agreement to drill all the PUD Wells, in which event the subordinated units would convert into common units on or before March 31, 2015.
     The table below sets forth the target distributions and subordination and incentive thresholds for each calendar quarter through the first quarter of 2015.
                         
    Subordination     Target     Incentive  
Period   Threshold     Distribution(1)     Threshold  
            (per unit)          
2011:
                       
First Quarter
  $ 0.446     $ 0.558     $ 0.669  
Second Quarter
    0.451       0.564       0.676  
Third Quarter
    0.550       0.688       0.825  
Fourth Quarter
    0.565       0.706       0.847  
2012:
                       
First Quarter
    0.574       0.717       0.861  
Second Quarter
    0.602       0.752       0.903  
Third Quarter
    0.624       0.780       0.937  
Fourth Quarter
    0.701       0.876       1.051  
2013:
                       
First Quarter
    0.756       0.945       1.135  
Second Quarter
    0.754       0.942       1.131  
Third Quarter
    0.701       0.876       1.052  
Fourth Quarter
    0.659       0.824       0.989  
2014:
                       
First Quarter
    0.610       0.763       0.915  
Second Quarter
    0.589       0.736       0.883  
Third Quarter
    0.571       0.713       0.856  
Fourth Quarter
    0.549       0.687       0.824  
2015:
                       
First Quarter
    0.519       0.649       0.779  
 
(1)   Target Distributions do not represent minimum quarterly distributions. There is no guarantee that the Trust will pay distributions at the target distribution level in any quarter.

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THE ROYALTIES
     The Underlying Properties consist of the working interests owned by ECA and the Private Investors in the Marcellus Shale formation in Greene County, Pennsylvania arising under leases and farmout agreements related to properties from which the Royalties were conveyed. ECA believes that there are in excess of 100 potential drilling locations for the PUD Wells within the AMI. As of December 31, 2010, the total gas reserves attributable to the trust interests were 102.4 Bcf. This amount includes 59.9 Bcf attributable to the proved undeveloped reserves and 42.49 Bcf attributable to the proved developed reserves. ECA is currently the operator of all of the wells subject to the PDP Royalty Interest. ECA has an average working interest of approximately 93% in the wells subject to the PDP Royalty Interest. Two third parties hold an approximate 50% and 35% working interest in two Producing Wells. ECA holds the remaining approximate 50% and 65% working interest in such wells. The reserves attributable to the Royalties include the reserves that are expected to be produced from the Marcellus Shale formation during the 20-year period in which the trust owns the Royalties as well as the residual interest in the reserves that the trust will sell on or shortly following the Termination Date.
SELECTED FINANCIAL DATA
     The following table provides a summary of proceeds received by the Trust and distributable income by quarter for 2010. ECA has not yet fulfilled its drilling obligation, and consequently the information in the table set forth below will not be comparable to the trust’s results going forward as ECA completes additional wells. For more information please read our financial statements included in this prospectus beginning on page F-1.
                                         
    Quarter Ended          
2010   March 31     June 30     September 30     December 31     Total  
    (all amounts in thousands except for distributable income per unit)      
Net proceeds
  $     $ 5,566     $ 7,918     $ 9,188     $ 22,672  
Distributable income
  $     $ 4,789     $ 7,419     $ 8,809     $ 21,017  
Distributable income per unit
  $     $ 0.272     $ 0.421     $ 0.500     $ 1.193  
TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
For the Three Months Ended December 31, 2010
     The trust’s distributable income was $8,809,013 for the three months ended December 31, 2010. This amount was less than the projected cash available for distribution determined in establishing the target distributions described in the Initial Prospectus by approximately $1.7 million.
     Total revenues for the quarter of $9.2 million were $1.7 million less than the projected amount of $10.9 million. This decrease in revenues was primarily the result of the $4.60 per Mcf average price realized for the quarter being $0.92 per Mcf lower than the projected price of $5.52 per Mcf. This was partially offset by production volumes being greater than projected by 17 MMcf. Twenty wells (14 Producing Wells and 6 PUD Wells) were online and producing at the end of the quarter, which was two less than projected in the Initial Prospectus.
     The average $4.60 per Mcf price realized for the quarter was lower than projected primarily as a result of the weighted average closing NYMEX price of $3.81 per Dth being lower than the projected price of $5.21 per Dth for the quarter. This lower weighted average NYMEX price was partially offset as a result of the hedge proceeds received for the quarter being $1.2 million greater than projected due to the lower NYMEX price.
     Total production for the quarter of 1,996 MMcf was 17 MMcf higher than projected. Twenty wells (14 Producing Wells and 6 PUD Wells) were online and producing at the end of the quarter, which was two less than projected. Of the six PUD Wells, four of these wells were brought online during the quarter ended December 31, 2010. One well was brought online in late October, two in mid November, and one in late December. These four

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wells had an average daily production rate, net to the trust, of 3,924 Mcf per day for January 2011. The average gross initial per well production for the first thirty days of production for these four wells was 3,159 Mcf per day which is 39.7% above the rate forecasted by the Ryder Scott reserve report described in the Initial Prospectus for the same time period.
     General and administrative expenses paid by the trust were $380,000 for the three months ended December 31, 2010. This amount was $31,000 less than the projected expenses for the quarter, primarily due to the timing of payment of invoices including the Trustee quarterly fee of $37,500 that was not paid until January 2011. During the three months ended December 31, 2010, ECA received a quarterly Administrative Services Fee of $15,000.
From Inception to December 31, 2010
     The Trust’s distributable income was $21,016,633 from inception through December 31, 2010. This amount was less than the projected cash available for distribution determined in establishing the target distributions described in the Initial Prospectus by approximately $0.8 million.
     Total revenues from inception through December 31, 2010 of $22.7 million were $0.4 million less than the projected amount of $23.1 million. This decrease in revenues was primarily the result of the $4.95 per Mcf average price realized for the period being $0.7574 per Mcf lower than the projected price of $5.69 per Mcf. This was partially offset by production volumes being greater than projected by 530 MMcf. Twenty wells (14 Producing Wells and 6 PUD Wells) were online and producing at the end of the period, which was two less than projected.
     The average $4.95 per Mcf price realized for the period was lower than projected primarily as a result of the weighted average closing NYMEX price of $4.05 per Dth being lower than the projected price of $4.91 per Dth for the period. This lower weighted average NYMEX price was partially offset as a result of the hedge proceeds received being $1.6 million greater than projected due to the lower NYMEX price.
     Total production for the period of 4,583 MMcf was 530 MMcf higher than projected. Twenty wells (14 Producing Wells and 6 PUD Wells) were online and producing at the end of the period, which was two less than projected. Of the six PUD Wells, two were brought online in mid September, one was brought online in late October, two in mid November, and one in late December. These six wells had an average daily production rate, net to the trust, of 6,578 Mcf per day for January 2011. The average gross initial per well production for the first thirty days of production for these six wells was 2,854 Mcf per day which is 26.3% above the rate forecasted by the Ryder Scott reserve report described in the Initial Prospectus for the same time period.
     General and administrative expenses paid by the trust were $1.0 million for the period ended December 31, 2010. This amount was $0.2 million less than the projected expenses. The Trustee elected to waive its quarterly fee of $37,500 and ECA elected to waive its quarterly Administrative Services Fee of $15,000 for the quarter ended June 30, 2010. Neither the Trustee nor ECA waived its fees for the quarter ended September 30, 2010 or December 31, 2010 and neither intends to do so in the future. Since inception, the Trustee has established a net cash reserve of $500,000 for use in paying current and future liabilities of the trust as they become due. The Trustee currently intends to maintain the reserve at this level, but may increase or decrease it at any time. This cash reserve reduced the trust’s distributable income for the period from inception to December 31, 2010.
     Because the Trust reached the incentive distribution threshold amount to be paid on all trust units for the quarters ended June 30, 2010, ECA received $58,688 (half of the amount in excess of the threshold) as an incentive distribution, and an additional $58,688 (the other half of the amount in excess of the threshold) as reimbursement for accrued interest on the floor contract premiums, which are to be repaid to ECA during the subordination period when the incentive distribution threshold amount is reached for all trust units in any quarter.
Recent Developments
     ECA has drilled an additional fifteen PUD Wells as of February 28, 2011 and thirteen of these wells are undergoing or awaiting completion operations while two were brought online in early January 2011. As of February 28, 2011, ECA had drilled a total of twenty-one actual PUD Wells. However, the average horizontal lateral distance for these twenty-one wells (as measured from the midpoint of the curve to the end of the lateral) was 3,864 feet and

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represents a total of 26.83 net PUD Wells drilled, calculated as described in the Development Agreement. These 26.83 net PUD Wells drilled count toward the 52 equivalent PUD Wells ECA has committed to drill. The trust expects that ECA will complete its drilling obligation on or before March 31, 2013.
Liquidity and Capital Resources
     The Trust has no source of liquidity or capital resources other than cash flows from the Royalties. Other than trust administrative expenses, including any reserves established by the Trustee for future liabilities, the trust’s only use of cash is for distributions to trust unitholders, including, if applicable, incentive distributions to ECA and, if applicable, expense reimbursements to ECA. Administrative expenses include payments to the Trustee and the Delaware Trustee as well as a quarterly fee of $15,000 to ECA pursuant to the Administrative Services Agreement. Each quarter, the Trustee determines the amount of funds available for distribution. Available funds are the excess cash, if any, received by the trust from the Royalties and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the trust’s expenses for that quarter, subject in all cases to the subordination and incentive provisions described above. Available funds are reduced by any cash the Trustee determines to hold as a reserve against future expenses or liabilities. The Trustee may borrow funds required to pay expenses or liabilities if the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the trust’s expenses or liabilities. If the Trustee borrows funds, the trust unitholders will not receive distributions until the borrowed funds are repaid.
     Payments to the Trust in respect of the Royalties are based on the complex provisions of the various conveyances held by the trust, copies of which are filed as exhibits to this registration statement, and reference is hereby made to the text of the conveyances for the actual calculations of amounts due to the trust.
     The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the trust’s liquidity or the availability of capital resources.
NATURAL GAS RESERVES
     Ryder Scott estimated natural gas reserves attributable to the Royalties as of December 31, 2010. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.
     Proved reserves of the Royalties. The following table, effective as of December 31, 2010, contains certain estimated proved reserves, estimated future net cash flows and the discounted present value thereof attributable to the Royalties, in each case derived from the reserve report. The reserve report was prepared by Ryder Scott in accordance with criteria established by the SEC. In accordance with the SEC’s rules, the reserves presented below were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 31, 2010, without giving effect to any derivative transactions, and were held constant for the life of the properties. This yielded a price for natural gas of $4.65 per Mcf. Proved reserve quantities attributable to the Royalties are calculated by multiplying the gross reserves less fuel usage and line loss for each property by the royalty interest assigned to the trust in each property. The net cash flows attributable to the trust’s reserves are net of the trust’s obligation to reimburse ECA for the post-production costs. The reserves and cash flows attributable to the trust’s interests include only the reserves attributable to the Royalties that are expected to be produced within the 20-year period in which the trust owns the royalty interest as well as the 50% residual interest in the reserves that the trust will own on the Termination Date. A summary of the reserve report is included as Annex A to this prospectus.
                         
    Proved Gas             Discounted  
    Reserves     Estimated Future     Estimated Future  
Proved reserves   (Bcf)     Net Cash Flows     Net Cash Flows (1)  
    (Dollars in thousands)  
Royalty Interests:
                       
Proved Developed (2)
    42.486     $ 174,607     $ 98,757  
Proved Undeveloped
    59.963       246,430       132,485  
 
                 
Total
    102.449     $ 421,037     $ 231,242  
 
                 
 
(1)   The present values of future net cash flows for the Royalties were determined using a discount rate of 10% per annum.

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(2)   Includes reserves currently behind pipe in wells which are in the process of being completed.
     Information concerning historical changes in net proved reserves attributable to the Royalties, and the calculation of the standardized measure of discounted future net cash flows related thereto, is contained in the unaudited supplemental information contained elsewhere in this prospectus.
THE RESERVE REPORT
     Technologies. The reserve report was prepared using decline curve analysis to determine the reserves of individual Producing Wells. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves which can be expected from any individual undeveloped well in the field. The consistency of reserves attributable to the Producing Wells, which cover a wide area of the AMI, further supports proved undeveloped classification.
     Also, a 3-D seismic survey was shot and interpreted across substantially all of the AMI and has been used to confirm the consistency of important reservoir properties throughout the AMI. Seismic interpretation has been used to support ECA’s belief of a consistency of Marcellus Shale formation thickness across the AMI, which is further substantiated by electric log and mudlog data from wells drilled on the Underlying Properties and adjacent wells drilled by third-party operators. Also, ECA has recently begun using seismic analysis of structural features on the Underlying Properties to optimally place PUD Wells within the acreage. By observing faults and other structural features within the acreage, ECA is able to place PUD Wells so that they will have the longest lateral length possible while staying in the Marcellus Shale formation by avoiding significant faults. The location of these faults also confirms the number of potential proved undeveloped locations on the acreage and indicates that the PUD locations will be able to be drilled without crossing significant faults or encountering structural features, such as steeply dipping beds near faults, which could limit lateral length. Electric logs and other geologic and engineering data gathered from proved developed wells and vertical Marcellus Shale wells ECA has previously drilled across the AMI further support the consistency of the Marcellus Shale reservoir throughout the AMI. Finally, ECA regularly trades geologic, engineering, and operations data with other operators in the area surrounding the AMI. This technical and production data further supports the consistency of the Marcellus Shale in and around the AMI.
     While a number of PUD Wells within the Underlying Properties are not direct offsets of other producing wells, both ECA and Ryder Scott, as independent petroleum engineers, were reasonably certain that all of the undrilled wells could be classified as PUD Wells because of the consistency of the Marcellus Shale formation across the AMI. As noted above, 3-D seismic data has been used to target PUD Well placement so as to avoid encountering significant faults or structural features. Data from both ECA and offset operators with which ECA has exchanged technical data demonstrate a consistency in this resource play over an area much larger than the AMI. In addition, direct measurement from other producing wells has also been used to confirm consistency in reservoir properties such as total organic content, vitrinite reflectance, porosity, thickness, and stratigraphic conformity. Most importantly, production from other producing wells confirms that horizontal Marcellus Shale wells across the AMI have similar performance with respect to initial production, decline curve shape, and estimated ultimate recovery.
     Internal Controls. Ryder Scott prepared its report as described above in accordance with appropriate engineering, geologic, and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry, and definitions and guidelines established by the SEC. These reserves, estimation methods and techniques are widely taught in university petroleum curricula and throughout the industry’s ongoing training programs. Although these appropriate engineering, geologic, and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry are based upon established scientific concepts, the application of such principles involves extensive judgment and is subject to changes in existing knowledge and technology, economic conditions and applicable statutory and regulatory provisions. The same industry wide applied techniques are used in determining estimated reserve quantities. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Society of Petroleum Engineering Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information. ECA has advised the Trust that it maintains adequate controls over the underlying data it provides to Ryder Scott, which is designed to result in accurate and reliable data in compliance with applicable regulations and guidance. The data ECA furnishes to Ryder Scott is reviewed by staff reservoir engineers and geoscientists before review by the Senior Reservoir Engineer and finally the Vice President of Eastern Operations. These individuals consult regularly with Ryder Scott

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during Ryder Scott’s reserve estimation process to review properties, assumptions, and any new data available. ECA’s Senior Reservoir Engineer has a Bachelor of Science in Petroleum Engineering. He has over 3 years of oil and gas industry experience in reservoir Engineering. ECA’s Vice President of Eastern Operations is the primary technical person responsible for overseeing the data reporting process. This individual has a Bachelor of Science degree in Chemical Engineering with Masters of Petroleum Engineering coursework along with a Master of Business Administration degree. He has worked in drilling, completions, production, and reservoir engineering along with acquisitions during his career and is a member of the Society of Petroleum Engineers.
Material Changes. Since the March 31, 2010 reserve report, ECA completed the six Producing Wells which were in the process of being completed and were noted in the March 31, 2010 reserves as “currently behind pipe in existing wells”. Also during this time, ECA drilled and completed the first six PUD wells, which have since been classified as proved developed. Finally, ECA drilled two additional PUD Wells which were included in proved developed reserves as of December 31, 2010, and were completed but awaiting initial production.
Well Locations
     ECA has over 100 locations within the AMI and may drill some of the PUD Wells on units that encompass land controlled by third-party operators in order to maximize recovery in the field and also maximize the lateral length of each PUD Well drilled. If ECA drills one or more PUD Wells in which it controls less than 100% working interest, it will be obligated to drill additional PUD Wells above the 52 planned for the trust in order to make the total number of net (equivalent) PUD Wells equal 52, provided that ECA may be required to drill fewer gross development wells due to lateral length from any well or wells exceeding 2,500 feet. For instance, if ECA drilled one well in which it controlled 50% working interest, and it was drilled to a horizontal lateral length of 2,500 feet, this well would only count as one-half of a PUD Well. In order to compensate for this, ECA would be obligated to drill an additional PUD Well with a horizontal lateral length of 2,500 feet and a 50% working interest so that the trust still received in total 52 equivalent wells.
SALE AND ABANDONMENT OF UNDERLYING PROPERTIES
     ECA and any transferee will have the right to abandon its interest in any well or property comprising a portion of the Underlying Properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the potential conflict of interest between ECA and the Trust in determining whether a well is capable of producing in commercially paying quantities, ECA is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as a burden affecting such property.
     After completion of its drilling obligation, ECA generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Royalties, without the consent of the trust unitholders. In addition, ECA may, without the consent of the trust unitholders, require the Trust to release royalty interests with an aggregate value to the Trust not to exceed $5.0 million during any 12-month period. These releases will be made only in connection with a sale by ECA of the Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such Royalties. ECA operates all of the Producing Wells and will operate not less than 90% of the PUD Wells during the subordination period. Any net sales proceeds paid to the trust are distributable to trust unitholders for the quarter in which they are received. ECA has not identified for sale any of the Underlying Properties.

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MARKETING AND POST-PRODUCTION SERVICES
     Pursuant to the terms of the conveyances creating the Royalties, ECA has the responsibility to market, or cause to be marketed, the natural gas production related to the Royalties. The terms of the conveyances creating the Royalties do not permit ECA to charge any marketing fee when determining the proceeds upon which the royalty payments will be calculated. As a result, the proceeds to the trust from the sales of natural gas production attributable to the Royalties will be determined based on the same price (net of post-production costs) that ECA receives for natural gas production attributable to ECA’s retained interest.
     A wholly owned subsidiary of ECA markets the majority of ECA’s operated production and markets substantially all of the gas produced attributable to the Royalties. Such subsidiary enters into gas sales arrangements with large aggregators of supply and these arrangements may be on a month-to-month basis or may be for a term of up to one year or longer. The natural gas is sold at a market price and subsequently any applicable post-production costs will be deducted. The Trust will not be charged any fee for marketing by ECA. Currently the primary aggregators of supply with whom ECA currently does business in the AMI are BP Energy Company, Centerpoint Energy Services, Inc., South Jersey Resource Group and Hess Corporation. In addition to providing marketing services, ECA’s subsidiary purchases all of the production from the Underlying Properties and those sales account for 100% of the revenue attributable to the Royalties.
     Substantially all of the production from the Producing Wells and the PUD Wells is or will be gathered by ECA’s Greene County Gathering System. The Trust pays the initial Post-Production Services Fee of $0.52 per MMBtu for use of this system, including ECA’s costs to gather, compress, transport, process, treat, dehydrate and market the gas. This fee is fixed until ECA’s drilling obligation is satisfied; thereafter, ECA may increase this fee to the extent necessary to recover certain capital expenditures on the Greene County Gathering System made after the completion of the drilling period, provided the resulting charge does not exceed the prevailing charges in the area for similar services. This fee does not include the cost of fuel used in the compression process or equivalent electricity charges when electric compressors are used. The December 31, 2010 reserve report described elsewhere in this registration statement assumes a 5% retainage for compression fuel and line loss on the Greene County Gathering System. This percentage represents current operating conditions, though such level may fluctuate going forward. The trust’s cash available for distribution will be reduced by ECA’s deductions for these post-production services.
     ECA or one of its affiliates may enter into arrangements with third parties to provide gathering, transportation, processing and other reasonable post-production services, including transportation on downstream interstate pipelines. Such additional post-production costs will be expressed as either (1) a cost per MMBtu or Mcf or (2) a percentage of the gross production from a well. To the extent that post-production costs are expressed as a cost per MMBtu or Mcf, such costs may be deducted by the ultimate purchaser of the natural gas prior to payment being made to ECA or its marketing affiliate for such production. At other times, ECA or its marketing affiliate will make payments directly to the third parties providing such post-production services. In either instance, the Trust’s cash available for distribution will be reduced by the costs paid by ECA for such post-production services provided by third parties. If the post-production costs are expressed as a percentage of the gross production from a well, then the volume of production from that well actually available for sale is less the applicable percentage charged, and as a result the reserves associated with that well that are attributable to the royalty interest are reduced accordingly.
     The post-production costs for natural gas production from the Producing Wells were $0.52 per MMBtu as of December 31, 2010. However, such costs may increase or decrease in the future. The post-production costs attributable to third party arrangements may be costs established by arms-length negotiations or pursuant to a state or federal regulatory proceeding. ECA will be permitted to deduct from the proceeds available to the trust other post-production costs necessary to make the natural gas attributable to the Royalties marketable, so long as such costs do not materially exceed the charges prevailing in the area for similar services.
     ECA recently executed a binding precedent agreement with a third party to provide firm transportation downstream of ECA’s Greene County Gathering System for 50,000 Dth per day. This firm transportation arrangement is scheduled to be in service August 1, 2011 and will be at the third party’s filed tariff rate, which equates to $0.1996 per MMbtu at one hundred percent loadfactor. This is a post-production cost which will ensure downstream capacity and such costs will be charged to the trust’s interest.

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     ECA expects to enter into similar gas supply arrangements and post-production service arrangements for the gas to be produced from the underlying PUD properties. Any new gas supply arrangements or those entered into for providing post-production services, will be utilized in determining the proceeds attributable to the Royalties.
TITLE TO PROPERTIES
     The Underyling Properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect ECA’s rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the trust’s interests and in estimating the size and the value of the reserves attributable to the Royalties.
     ECA acquired its interests in the Underlying Properties through a variety of means, including through the acquisition of oil and gas leases by ECA directly from the mineral owner, through assignments of oil and gas leases to ECA by the lessee who originally obtained the leases from the mineral owner, through farmout agreements that grant ECA the right to earn interests in the properties covered by such agreements by drilling wells, and through acquisitions of other oil and gas interests by ECA.
     ECA’s interests in the gas properties comprising the Underlying Properties are typically subject, in one degree or another, to one or more of the following:
    royalties and other burdens, express and implied, under gas leases;
 
    production payments and similar interests and other burdens created by ECA or its predecessors in title;
 
    a variety of contractual obligations arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;
 
    liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;
 
    pooling, unitization and communitization agreements, declarations and orders;
 
    easements, restrictions, rights-of-way and other matters that commonly affect property;
 
    conventional rights of reassignment that obligate ECA to reassign all or part of a property to a third party if ECA intends to release or abandon such property; and
 
    rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and the royalty interests therein.
     ECA believes that the burdens and obligations affecting the Underlying Properties are conventional in the industry for similar properties. ECA also believes that the burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the value of the Royalties.
     ECA believes that its title to the Underlying Properties, and the trust’s title to the Royalties, is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material as to detract substantially from the use or value of such properties or Royalties. Consistent with industry practice, ECA has not obtained preliminary title reviews of the PUD Wells that have not been drilled. Prior to drilling each new PUD Well, ECA intends to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examination, certain curative work must be done to correct defects in the marketability of title. ECA does not intend to perform any further title examination other than the preliminary title review conducted prior to the drilling of a PUD Well. The conveyances related to the PUD Royalty Interest obligate ECA to conduct a more thorough title examination of the drill site tract prior to drilling any of the PUD Wells. ECA will not be relieved of its obligation to drill a well if such title examination prior to drilling reveals a title defect preventing ECA from drilling in such drill site.

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     It is unclear under Pennsylvania law whether the Royalties would be treated as real property interests. Nevertheless, ECA has recorded the conveyances of the Royalties in the real property records of Pennsylvania in accordance with local recording acts. ECA has granted to the Trust the Royalty Interest Lien to provide protection to the Trust, in the event of a bankruptcy of ECA, against the risk that the Royalties were not considered real property interests.
COMPETITION AND MARKETS
     The natural gas industry is highly competitive. ECA competes with major oil and gas companies and independent oil and gas companies for oil and gas leases, equipment, personnel and markets for the sale of natural gas. Many of these competitors are financially stronger than ECA, but even financially troubled competitors can affect the market because they may need to sell natural gas regardless of price to attempt to maintain cash flow. The Trust is subject to the same competitive conditions as ECA and other companies in the natural gas industry.
     Natural gas competes with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for natural gas.
     Future price fluctuations for natural gas will directly affect trust distributions, estimates of reserves attributable to the trust’s interests, and estimated and actual future net revenues to the trust. In view of the many uncertainties that affect the supply and demand for natural gas, neither the Trust nor ECA can make reliable predictions of future gas supply or demand, future gas prices or the effect of future gas prices on the trust.
REGULATION
     Natural gas regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.
     Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. Neither ECA nor the trust can predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the Underlying Properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.
     Environmental regulation. The exploration, development and production operations of ECA are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct drilling, water withdrawal and waste disposal operations; govern the amounts and types of substances that may be disposed or released into the environment; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions arising from ECA’s operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of ECA’s operations in affected areas.
     The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on ECA’s operations and financial position. ECA may be unable to pass on such increased compliance costs to its customers. Moreover, accidental releases or spills may occur in the course of ECA’s operations, and there can be no assurance that ECA will not incur significant costs

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and liabilities as a result of such releases or spills, including any third party claims for damage to property and natural resources or personal injury. While ECA believes that it is in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on it, there is no assurance that this trend will continue in the future.
     The following is a summary of the more significant existing environmental, health and safety laws and regulations to which ECA’s business operations are subject and for which compliance may have a material adverse impact on ECA’s capital expenditures, results of operations or financial position.
     Hazardous Substances and Wastes. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, (“CERCLA”), also known as the Superfund law and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. ECA generates materials in the course of ECA’s operations that may be regulated as hazardous substances.
     ECA also generates solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of its operations, ECA generates petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes.
     ECA currently owns or leases, and in the past may have owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although ECA may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by ECA or on or under the other locations where these petroleum hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under ECA’s control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, ECA could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations to prevent future contamination.
     Air Emissions. The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require ECA to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of natural gas projects. While ECA may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, ECA does not believe that such requirements will have a material adverse effect on its operations.
     Climate Change. In response to certain scientific studies suggesting that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”) and including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic changes, the EPA determined in December 2009 that emissions of GHGs present an endangerment to public health and the environment. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources under the Prevention of Significant Deterioration

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(“PSD”) and Title V permitting programs, effective January 2, 2011. This stationary source rule “tailors” these permitting programs to apply to certain stationary sources in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that will be established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. In addition, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities, beginning in 2012 for emissions occurring in 2011.
     In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.
     The adoption of legislation or regulatory programs to reduce emissions of GHGs could require ECA to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas ECA produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on ECA’s business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on ECA’s financial condition and results of operations.
     Water Discharges. The Federal Water Pollution Control Act, as amended (“Clean Water Act”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws, including Pennsylvania, require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.
     It is customary to recover natural gas from deep shale formations, including the Marcellus Shale formation, through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study expected to be available in late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. In addition, legislation was introduced in the recently completed 111th Session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and such legislation could be introduced and adopted in the current session of Congress. Also, some states have adopted, including Pennsylvania, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. If new laws or regulations that

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significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for ECA to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, ECA’s fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that ECA is ultimately able to produce.
     Endangered Species Act. The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. While some of ECA’s facilities or leased acreage may be located in areas that are designated as habitat for endangered or threatened species, ECA believes that it is in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause ECA to incur additional costs or become subject to operating restrictions or bans in the affected areas.
     Employee Health and Safety. The operations of ECA are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in ECA’s operations and that this information be provided to employees, state and local government authorities and citizens. ECA believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.
     State regulation. Pennsylvania regulates the drilling for, and the production, gathering and sale of, natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells, production rates and the prevention of waste of natural gas resources. Realized prices are not currently subject to state regulation or subject to other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from ECA’s wells and to limit the number of wells or locations ECA can drill.

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DESCRIPTION OF THE ROYALTIES
          The Royalties were conveyed to the Trust by ECA by means of conveyance instruments that have been recorded in the appropriate real property records in Greene County, Pennsylvania where the Underlying Properties to which the Royalties relate are located. The PDP Royalty Interest burdens the existing working interests owned by ECA in the Producing Wells. ECA has an average working interest of approximately 93% in these wells.
          The PUD Royalty Interest burdens 50% of all of the interests of ECA in the Marcellus Shale formation in the AMI. ECA’s interests in the Underlying Properties to which the PUD Wells relate consist of an average working interest of 100%. The conveyances related to the PUD Royalty Interest, however, provide that the proceeds from the PUD Wells will be calculated on the basis that the PUD Wells are only burdened by interests that in total would not exceed 12.5%. In the event that ECA’s interest in any of the wells subject to the PUD Royalty Interest that are drilled is subject to burdens in excess of a 12.5%, such burdens will be fully allocated against ECA’s retained interest in such well, the net effect of which is that the trust will receive payments with respect to the PUD Royalty Interest as if the burdens effecting the PUD Wells were in total 12.5% (proportionately reduced).
     Generally, the percentage of production proceeds to be received by the Trust with respect to a well will equal the product of (i) the percentage of proceeds to which the trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) ECA’s net revenue interest in the well. ECA on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the trust is entitled to receive on average 73.37% of the proceeds of production from the Producing Wells. With respect to a PUD Well, the conveyances related to the PUD Royalty Interest provide that the proceeds from the PUD Wells will be calculated on the basis that the underlying PUD Wells are burdened only by interests that in total would not exceed 12.5% of the revenues from such properties, regardless of whether the royalty interest owners are actually entitled to a greater percentage of revenues from such properties. As the applicable net revenue interest of a well is calculated by multiplying ECA’s percentage working interest in such well by the unburdened interest percentage (87.5%), assuming ECA owns a 100% working interest in a PUD Well, such well would have a minimum 87.5% net revenue interest. Accordingly, the trust would be entitled to 43.75% of the production proceeds from such well.
     Pursuant to the Development Agreement, ECA will satisfy its drilling obligation only when it has drilled 52 equivalent wells. The proved undeveloped reserves included in the reserve report represent the reserves assigned to undeveloped locations that ECA anticipates drilling. However, under the conveyances, ECA is obligated to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such properties. Accordingly, there may be situations where ECA will be obligated to drill on one or more of the over 100 potential drilling locations within the AMI, including the 52 drilling locations identified in the reserve report, that are not those identified locations underlying the reserve report.
     Based on extensive geologic and engineering data from the Producing Wells and vertical Marcellus Shale wells in the AMI, as well as 3-D seismic testing within the region, ECA believes that the Marcellus Shale formation has demonstrated consistency in formation thickness and other important characteristics across the AMI. When combined with the fact that ECA is obligated to operate as a reasonably prudent operator with respect to the PUD Wells, ECA believes that a deviation from the 52 identified drilling locations underlying the reserve report would not occur absent a reasonable belief that (i) such deviation would not result in production at least equal to that of the location deviated from, and (ii) not materially reduce the anticipated reserves attributable to the 52 equivalent wells forming the PUD Wells. To the extent ECA’s working interest in a PUD Well is less than 100%, the trust’s share of proceeds would be proportionately reduced. Pursuant to the Development Agreement, however, ECA will only satisfy its drilling obligation when it has drilled 52 equivalent wells. Therefore, any reduction in production proceeds attributable to a PUD Well caused by ECA having less than a 100% working interest in the well will be offset by the requirement to drill additional wells. An equivalent PUD Well is calculated by multiplying the working interest held by ECA by the horizontal lateral length of the well relative to 2,500 feet. PUD Wells drilled horizontally in the Marcellus Shale formation with a horizontal lateral distance (measured from the midpoint of the curve to the end of the lateral) of less than 2,500 feet will count as a fractional well in proportion to total lateral length divided by 2,500 feet. In the event ECA commences drilling of a PUD Well but fails to drill beyond the mid-point of the curve, such well will not count as a fractional well. PUD Wells with a horizontal lateral distance of greater than 2,500 feet (subject to a maximum of 3,500 feet) will count as one well plus a fractional well equal to the length drilled in excess of 2,500 (up to 3,500 feet) feet divided by 2,500 feet. Accordingly, for example, if ECA

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drilled one well in which it has a 50% working interest, and such well was drilled to a horizontal lateral length of 2,500 feet, such well would count for purposes of the Development Agreement as only 0.50 PUD Wells. In order to compensate for this, ECA would be obligated to drill an additional 0.50 PUD Wells. Such additional 0.50 PUD Wells could be achieved, for example, by drilling an additional PUD Well with a horizontal lateral length of 3,000 feet (or 500 feet longer than the 2,500 foot base lateral length) in which ECA holds a 41.7% working interest, or by drilling an additional PUD Well with a horizontal lateral length of 2,000 feet (or 500 feet shorter than the 2,500 foot base lateral length) in which ECA holds a 62.5% working interest. ECA believes that longer laterals will produce more reserves both in the near term and ultimately. Consequently, longer lateral distances achieved should provide incremental benefit to the trust. The maximum credit ECA can earn toward the 52 well requirement under the Development Agreement by drilling a single actual well is 1.4 wells, calculated as described above.
     PDP Royalty Interest. The conveyances creating the PDP Royalty Interest entitle the Trust to receive an amount of cash for each calendar quarter equal to 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of estimated natural gas production attributable to the Producing Wells regardless of whether such amounts have actually been received by ECA from the purchases of the natural gas produced. Proceeds from the sale of natural gas production attributable to the Producing Wells in any calendar quarter means:
    amount calculated based on estimated production volumes attributable to the Producing Wells;
in each case, after deducting the Trust’s proportionate share of:
    any taxes levied on the severance or production of the natural gas produced from the Producing Wells and any property taxes attributable to the natural gas production attributable to the Producing Wells; and
 
    post-production costs, which generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production costs on its Greene County Gathering System will be limited to $0.52 per MMBtu of gas gathered until ECA has fulfilled its drilling obligation. Thereafter, ECA may increase this Post-Production Service Fee to the extent it is necessary to recover certain capital expenditures in ECA’s Greene County Gathering System. Additionally, the trust is charged for the cost of fuel used in the compression process, including equivalent electricity charges in instances when electric compressors are used.
     Proceeds payable to the Trust from the sale of natural gas production attributable to the Producing Wells in any calendar quarter are not subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production of natural gas production attributable to the Producing Wells, including any costs to plug and abandon a Producing Well.
     PUD Royalty Interest. The conveyances creating the PUD Royalty Interest entitle the Trust to receive an amount of cash for each calendar quarter equal to 50% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of estimated natural gas production attributable to the PUD Wells regardless of whether such amounts have actually been received by ECA from the purchase of the natural gas produced. Proceeds from the sale of natural gas production, if any, attributable to the PUD Wells in any calendar quarter means:
    for any calendar quarter commencing on or after April 1, 2010, the amount calculated based on estimated production volumes attributable to the PUD Wells:
in each case after deducting the Trust’s proportionate share of:
    any taxes levied on the severance or production of the natural gas produced from the PUD Wells and any property taxes attributable to the gas produced from the PUD Wells; and
 
    post-production costs generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production charges on its with ECA’s Greene County Gathering System is limited to $0.52 per MMBtu of gas gathered until ECA has fulfilled its drilling obligation. Thereafter, ECA may increase this Post-Production Services Fee to the extent is necessary to recover certain capital expenditures in ECA’s Greene County Gathering

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      System. Additionally, the Trust is charged for the cost of fuel used in the compression process, including equivalent electricity charges in instances when electric compressors are used.
     Proceeds, if any, payable to the Trust from the sale of natural gas production attributable to the PUD Wells in any calendar quarter:
    will be determined on the basis that ECA’s working interest with respect to the PUD Wells is not subject to burdens (landowner’s royalties and other similar interests) in excess of 12.5% of the proceeds from gas production attributable to ECA’s interest; and
 
    will not be subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production of natural gas production attributable to the underlying PUD properties, including any costs to plug and abandon a well included in the underlying PUD properties.
     Royalty Interest Lien
     Under the laws of Pennsylvania, it is not clear that the Royalties conveyed by ECA to the Trust would be treated as real property interests. Therefore, ECA has granted to the Trust the Royalty Interest Lien to provide protection to the Trust, exercisable in the event of a bankruptcy of ECA, against the risk that the Royalties were not considered real property interests. More specifically, the Royalty Interest Lien is a lien in the Subject Interest and the Subject Gas, to the extent and only to the extent that such Subject Interest and Subject Gas pertains to Gas in, under and that may be produced, saved or sold from the Marcellus Shale formation from the wellbore of the Producing Wells and the PUD Wells, sufficient to cause the trust to receive a volume of Trust Gas calculated in accordance with the provisions of the conveyances of the royalty interests. Capitalized terms used in the preceding sentence and not otherwise defined in this prospectus shall have the following meanings:
     “Gas” means natural gas and all other gaseous hydrocarbons, excluding condensate, butane, and other liquid and liquefiable components that are actually removed from the Gas stream by separation, processing, or other means.
     “Subject Gas” means Gas from the Marcellus Shale formation from any Producing Well or PUD Well.
     “Subject Interest” means ECA’s undivided interests in the AMI, as lessee under Gas leases, as an owner of the Subject Gas (or the right to extract such Gas), or otherwise, by virtue of which undivided interests ECA has the right to conduct exploration and Gas production operations on the AMI.
     “Trust Gas” means that percentage of Gas to which the trust is entitled, calculated in accordance with the provisions of the conveyances of the Royalties.
     The Royalty Interest Lien does not include ECA’s retained interest in the PUD and Producing Wells and the AMI or other interest of ECA in the AMI, and ECA has the right to lien, mortgage, sell or otherwise encumber the ECA retained interest subject to the Royalty Interest Lien.
     ECA has recorded the conveyances of the Royalties and a Mortgage/Fixture Filing in the real estate records of Greene County, Pennsylvania and has filed a corresponding UCC-1 Financing Statement in the Office of the Secretary of State of West Virginia and the Commonwealth of Pennsylvania.
     The conveyances also provide that if ECA’s interest with respect to the PDP properties is greater than what was warranted to the trust in the conveyances, ECA will have the right to offset against amounts owed to the trust, the difference between what the trust actually receives from PDP Royalty Interest and what the trust should have received from the PDP Royalty Interest had ECA’s interest been the amount warranted.
     Hedging Contracts Transferred to the Trust
     The primary asset of and source of income to the trust are the Royalties, which generally entitle the trust to receive varying portions of the net proceeds from gas production from the Underlying Properties. Consequently, the trust is exposed to market risk from fluctuations in gas prices. Through March 31, 2014, however, the Royalties are

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subject to the hedge contracts described below, which are expected to reduce the trust’s exposure to natural gas price volatility.
     The hedge contracts consist of natural gas derivative floor price contracts and a back-to-back swap agreement ECA entered into with the Trust to provide the trust with the benefit of certain contracts previously entered into between ECA and third parties that equate to approximately 50% of the estimated natural gas to be produced by the trust properties through March 31, 2014. The swap contracts relate to approximately 7,500 MMBtu per day at a weighted average price of $6.78 per MMBtu for the period commencing as of April 1, 2010 through June 30, 2012. The price of the floor price hedging contracts is $5.00 per MMBtu.
     The following table sets forth the volumes of natural gas covered by the natural gas hedging contracts and the floor price for each quarter during the term of the contracts.
                                 
    Swap Volume     Swap Price     Floor Volume     Floor Price  
    (MMBtu)     (MMBtu)     (MMBtu)     (MMBtu)  
2010
                               
Second Quarter
    682,500     $ 6.75              
Third Quarter
    690,000     $ 6.75              
Fourth Quarter
    690,000     $ 6.75       225,000     $ 5.00  
2011
                               
First Quarter
    675,000     $ 6.75       159,000     $ 5.00  
Second Quarter
    682,500     $ 6.75       210,000     $ 5.00  
Third Quarter
    690,000     $ 6.82       405,000     $ 5.00  
Fourth Quarter
    690,000     $ 6.82       384,000     $ 5.00  
2012
                               
First Quarter
    682,500     $ 6.82       369,000     $ 5.00  
Second Quarter
    682,500     $ 6.82       516,000     $ 5.00  
Third Quarter
                    1,305,000     $ 5.00  
Fourth Quarter
                    1,362,000     $ 5.00  
2013
                               
First Quarter
                    1,395,000     $ 5.00  
Second Quarter
                    1,380,000     $ 5.00  
Third Quarter
                    1,278,000     $ 5.00  
Fourth Quarter
                    1,188,000     $ 5.00  
2014
                               
First Quarter
                    1,092,000     $ 5.00  
     The Trust’s counterparties under the natural gas floor price contracts are Wells Fargo Foothill, Inc. and BP Energy Company, and its counterparty under the back-to-back swap agreement is ECA, whose counterparties are also Wells Fargo Foothill, Inc. and BP Energy Company. In the event that any of the counterparties to the natural gas hedging contracts default on their obligations to make payments to the trust, the cash distributions to the trust unitholders would likely be materially reduced as the hedge payments are intended to provide additional cash to the Trust during periods of lower natural gas prices. ECA will have no continuing obligation with respect to the natural gas floor price contracts. However, ECA will be the Trust’s counterparty under the back-to-back swap agreement and will have continuing obligations with respect to this agreement.
ADDITIONAL PROVISIONS
     If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:
    amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the underlying property until actually collected;
 
    amounts received by the owner of the underlying property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and
 
    amounts received by the owner of the underlying property and not deposited with an escrow agent will be considered to have been received.

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     The Trustee is not obligated to return any cash received from the Royalties. However, any overpayments made to the trust by ECA due to adjustments to prior calculations of proceeds or otherwise will reduce future amounts payable to the trust until ECA recovers the overpayments.
     The conveyances generally permit ECA to sell, without the consent or approval of the trust unitholders, all or any part of its interest in the Underlying Properties, if the Underlying Properties are sold, subject to and burdened by the Royalties. Notwithstanding the foregoing, the conveyances provide that ECA may not sell any of the Underlying Properties subject to the PUD Royalty Interest until it has satisfied its obligation to drill PUD Wells pursuant to the terms of the Development Agreement. The trust unitholders are not entitled to any proceeds of any sale of ECA’s interest in the Underlying Properties that remains subject to and burdened by the Royalties. Following any such sale, the proceeds attributable to the transferred property will be calculated pursuant to the conveyances as described in this registration statement, and paid by the purchaser or transferee to the Trust.
     Subject to the terms of the conveyances, ECA may at its option at any time prior to the completion of its drilling obligation, cause the trust to exchange leased acreage subject to the Royalties, free and clear of such Royalties, for other leased acreage within the AMI (as defined in the conveyances). Such leased acreage exchanged to the trust shall then be subject to the Royalties as set forth in the conveyances.
     Additionally, the conveyances provide that, in the event ECA acquires any additional leases in the AMI prior to the completion of its drilling obligation, ECA may at its option make such additional lease subject to the Royalties. In no event may any additional lease become subject to the Royalties, or any exchange of acreage be effected, unless ECA certifies to the trust that, among other things, all of the aggregate acreage attributable to the additional leases and exchange leases shall not exceed five percent of the acreage subject to the Royalties.
     ECA or any transferee of an Underlying Property will have the right to abandon any well or property if it reasonably believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. In making such decisions, ECA or any transferee of an Underlying Property is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. Upon termination of the lease, that portion of the royalty interests relating to the abandoned property will be extinguished.
     ECA may, without the consent of the trust unitholders, require the trust to release royalty interests with an aggregate value to the trust up to $5.0 million during any twelve month period. These releases will be made only in connection with a sale by ECA of the Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such royalty interests.
     The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. The Term Royalties will automatically revert to ECA at the Termination Date, while the Perpetual Royalties will be sold and the proceeds thereof will be distributed to the unitholders at the Termination Date or soon thereafter. ECA will have a first right of refusal to purchase the Perpetual Royalties at the Termination Date.
     ECA must maintain books and records sufficient to determine the amounts payable for the Royalties to the Trust. Quarterly and annually, ECA must deliver to the Trustee a statement of the computation of the proceeds for each computation period as well as quarterly drilling and production results. ECA is not a publicly held company, and although ECA has continuing obligations to the Trust, ECA has no obligation to publicly file any reports with the SEC.

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DESCRIPTION OF THE TRUST AGREEMENT
     The Trust was created under Delaware law to acquire and hold the Royalties for the benefit of the trust unitholders pursuant to an agreement between ECA, the Trustee and the Delaware Trustee. The Royalties are passive in nature and neither the Trust nor the Trustee has any control over or responsibility for costs relating to the operation of the Royalties. Neither ECA nor other operators of the Royalties have any contractual commitments to the trust to provide additional funding or to conduct further drilling on or to maintain their ownership interest in any of these properties other than the obligations of ECA to designate and drill PUD Wells.
     The trust agreement provides that the trust’s business activities are limited to owning the Royalties and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the Royalties and the natural gas hedging contracts relating to an estimated 50% of the Trust’s royalty production for a term ending March 31, 2014. As a result, the Trust is not permitted to acquire other oil and gas properties or royalty interests.
     The beneficial interest in the trust is divided into 17,605,000 trust units. The number of trust units is fixed and the Trust is not permitted to issue additional trust units. Each of the trust units represents an equal undivided beneficial interest in the assets of the trust; subject, however, to the provisions relating to the subordinated units. Please read “Description of the trust units” for additional information concerning the trust units.
     Amendment of the trust agreement generally requires a vote of holders of a majority of the outstanding trust units, except that amendments that would result in a materially disproportionate benefit to ECA or its affiliates compared to other owners of common units require a vote of the holders of a majority of the outstanding common units and a majority of the outstanding trust units. However, no amendment may:
    increase the power of the Trustee to engage in business or investment activities;
 
    alter the rights of the trust unitholders as among themselves; or
 
    permit the Trustee to distribute the royalty interests in kind.
     Certain amendments to the trust agreement do not require the vote of the trust unitholders. The Trustee may, without approval of the trust unitholders, from time to time supplement or amend the trust agreement in order to cure any ambiguity or to correct or supplement any defective or inconsistent provisions provided such supplement or amendment is not adverse to the interest of the trust unitholders. The business and affairs of the trust are managed by the Trustee. Although ECA operates all of the Producing Wells and substantially all of the PUD Wells during the subordination period, ECA has no ability to manage or influence the management of the trust.
ASSETS OF THE TRUST
     The assets of the Trust consist of the Royalties, natural gas hedging contracts, the Administrative Services Agreement, the Development Agreement, and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the trust unitholders.
DUTIES AND POWERS OF THE TRUSTEE
     The duties of the Trustee are specified in the trust agreement and by the laws of the State of Delaware, except as modified by the trust agreement. The Trustee’s principal duties consist of:
    collecting cash attributable to the royalty interests;
 
    paying expenses, charges and obligations of the trust from the trust’s assets;
 
    determining whether cash distributions exceed subordination or incentive thresholds, and making such cash distributions to the common and subordinated unitholders and ECA with respect to its right to receive incentive distributions and reimbursement of its approximately $5.0 million hedging costs;

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    causing to be prepared and distributed a Schedule K-1 for each trust unitholder and to prepare and file tax returns on behalf of the Trust; and
 
    causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading.
     If a Trust liability is contingent or uncertain in amount or not yet currently due and payable, the Trustee may create a cash reserve to pay for the liability. If the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the trust’s liability, the Trustee may borrow funds required to pay the liabilities. The Trustee may borrow the funds from any person, including itself or its affiliates. The terms of such indebtedness, if funds were loaned by the entity serving as Trustee or Delaware Trustee, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such indebtedness as if it were not then serving as Trustee or Delaware Trustee. If the Trustee borrows funds, the trust unitholders will not receive distributions until the borrowed funds are repaid.
     Each quarter, the Trustee pays trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the royalty interests. The cash held by the Trustee as a reserve against future liabilities must be invested in:
    interest bearing obligations of the United States government;
 
    money market funds that invest only in United States government securities;
 
    repurchase agreements secured by interest-bearing obligations of the United States government;
 
    bank certificates of deposit; or
 
    cash held for distribution at the next distribution date may be held in a non interest bearing account.
     The Trust may not acquire any asset except the Royalties, the natural gas hedging contracts, cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.
     The Trust may merge or consolidate with or into one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is agreed to by the Trustee and by the affirmative vote of the holders of a majority of the outstanding trust units (or by the holders of a majority of the common units and a majority of the outstanding trust units if such transaction would result in a materially disproportionate benefit to ECA or its affiliates compared to other owners of common units) and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law.
     The Trustee may sell the Royalties under any of the following circumstances:
    the sale is requested by ECA, following the satisfaction of its drilling obligation, in accordance with the provisions of the trust agreement; or
 
    the holders representing a majority of the outstanding trust units approving the sale (or by the holders of a majority of the common units and a majority of the outstanding trust units if such transaction would result in a materially disproportionate benefit to ECA or its affiliates compared to other owners of common units).
     Upon dissolution of the Trust the Trustee must sell the Royalties. No trust unitholder approval is required in this event.
     The Trustee distributes the net proceeds from any sale of the Royalties and other assets to the trust unitholders.

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     The Trustee may amend or supplement the trust agreement, the conveyances, the Development Agreement, the Administrative Services Agreement, the hedge agreements, the registration rights agreement, the Drilling Support Lien and the Royalty Interest Lien, without the approval of the trust unitholders, to cure ambiguities, to correct or supplement defective or inconsistent provisions, to grant any benefit to all trust unitholders, to add collateral to the Drilling Support Lien and the Royalty Interest Lien or to change the name of the trust, provided, however, that any such supplement or amendment does not adversely affect the interest of the trust unitholders. Furthermore, the Trustee, acting alone, may amend the Administrative Services Agreement without the approval of trust unitholders if such amendment would not increase the cost or expense of the trust or create an adverse economic impact on the trust unitholders. All other permitted amendments may only be made by the affirmative vote of a majority of the trust units (or by the holders of a majority of the common units and a majority of the outstanding trust units if such transaction would result in a materially disproportionate benefit to ECA or its affiliates compared to other owners of common units).
LIABILITIES OF THE TRUST
     Because the trust does not conduct an active business and the Trustee has little power to incur obligations, it is expected that the trust will only incur liabilities for routine administrative expenses, such as the Trustee’s fees and accounting, engineering, legal, tax advisory and other professional fees.
FEES AND EXPENSES
     The Trust is responsible for paying all legal, accounting, tax advisory, engineering, printing and other administrative and out-of-pocket expenses incurred by or at the direction of the Trustee or the Delaware Trustee. The Trust is also responsible for paying other expenses incurred as a result of its being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation and distribution, independent auditor fees and registrar and transfer agent fees. These costs as well as those to be paid to ECA pursuant to the Administrative Services Agreement outlined under “The trust — Administrative Services Agreement and Development Agreement,” will be deducted by the Trust before distributions are made to trust unitholders. From inception until December 31, 2010, the Trust incurred approximately $1.0 million in administrative fees including fees associated with formation and the initial public offering.
     The Administrative Services Agreement provides that the Trust is obligated, throughout the term of the trust, to pay to ECA each quarter an administrative services fee for accounting, bookkeeping and informational services relating to the Royalties. The annual fee, payable in equal quarterly installments, totals $60,000 per year.
RESPONSIBILITY AND LIABILITY OF THE TRUSTEE
     The duties and liabilities of the Trustee are set forth in the trust agreement. The trust agreement provides that (i) the Trustee shall not have any duties or liabilities, including fiduciary duties, except as expressly set forth in the trust agreement, and (ii) the duties and liabilities of the Trustee as set forth in the trust agreement replace any other duties and liabilities, including fiduciary duties, to which the Trustee might otherwise be subject.
     The Trustee does not make business decisions affecting the assets of the Trust. Therefore, substantially all of the Trustee’s functions under the trust agreement are expected to be ministerial in nature. See “— Duties and powers of the Trustee,” above. The trust agreement, however, provides that the Trustee may:
    charge for its services as Trustee;
 
    retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the Trustee to the extent permitted by law);
 
    lend funds at commercial rates to the trust to pay the trust’s expenses; and
 
    seek reimbursement from the trust for its out-of-pocket expenses.
     In discharging its duty to trust unitholders, the Trustee may act in its discretion and will be liable to the trust unitholders only for fraud, gross negligence or acts or omissions constituting bad faith. The Trustee will not be liable

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for any act or omission of its agents or employees unless the Trustee acted with fraud, in bad faith or with gross negligence in their selection and retention. The Trustee will be indemnified individually or as the Trustee for any liability or cost that it incurs in the administration of the trust, except in cases of fraud, gross negligence or bad faith. The Trustee will have a lien on the assets of the trust as security for this indemnification and its compensation earned as Trustee. See “Description of the trust units — Liability of trust unitholders.” The Trustee ensures that all contractual liabilities of the trust are limited to the assets of the trust.
DURATION OF THE TRUST; SALE OF ROYALTIES
     The Trust remains in existence until the Termination Date, which is March 31, 2030. The trust dissolves prior to the Termination Date if:
    the Trust sells all of the Royalties;
 
    gross proceeds attributable to the Royalties are less than $1.5 million for any four consecutive quarters;
 
    the holders of a majority of the outstanding trust units vote in favor of dissolution; or
 
    the Trust is judicially dissolved.
     The Trustee would then sell all of the Trust’s assets, either by private sale or public auction, and distribute the net proceeds of the sale to the trust unitholders.
DISPUTE RESOLUTION
     Any dispute, controversy or claim that may arise between ECA and the Trustee relating to the trust will be submitted to binding arbitration before a panel of three arbitrators.
COMPENSATION OF THE TRUSTEE AND THE DELAWARE TRUSTEE
     The Trustee’s and the Delaware Trustee’s compensation is paid out of the trust’s assets. See “— Fees and Expenses.”
TAX MATTERS
     Trust unitholders will be treated as partners of the Trust for federal income tax purposes. The trust agreement contains tax provisions that generally allocate the trust’s income, gain, loss, deduction and credit among the trust unitholders in accordance with their percentage interests in the trust. The trust agreement also sets forth the tax accounting principles to be applied by the Trust.
MISCELLANEOUS
     The Trustee may consult with counsel, accountants, tax advisors, geologists and engineers and other parties the Trustee believes to be qualified as experts on the matters for which advice is sought. The Trustee will be protected for any action it takes in good faith reliance upon the opinion of the expert.
     The Delaware Trustee and the Trustee may resign at any time or be removed with or without cause at any time by a vote of not less than a majority of the outstanding trust units. Any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20 million, in the case of the Delaware Trustee, and $100 million, in the case of the Trustee.
     The principal offices of the Trustee are located at 919 Congress Avenue, Suite 500, Austin, TX 78701, and its telephone number is 1-800-852-1422.

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DESCRIPTION OF THE TRUST UNITS
     Each trust unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis, subject to the subordination provisions described elsewhere in this registration statement. Subject to the subordination provisions, each trust unitholder has the same rights regarding trust units as every other trust unitholder. The Trust has 17,605,000 trust units outstanding, consisting of 13,203,750 common units and 4,401,250 subordinated units.
DISTRIBUTIONS AND INCOME COMPUTATIONS
     Cash distributions to trust unitholders are expected to be made from available funds at the Trust for each calendar quarter. Production payments due to the Trust with respect to any calendar quarter will be accrued based on estimated production volumes attributable to the trust properties during such quarter (as measured at ECA metering systems) and market prices for such volumes. ECA is expected to make a payment to the Trust equal to such accrued amounts within 30 days of the end of such calendar quarter. After receipt of such payment, the Trustee will determine for such calendar quarter the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the Trust over the Trust’s expenses for that quarter. Available funds will be reduced by any cash the Trustee decides to hold as a reserve against future liabilities. Any difference between the payment made by ECA to the Trust with respect to a calendar quarter and the actual cash production payments relative to the trust properties received by ECA will be netted against future payments by ECA to the Trust. As a result, during the subordination period, the netting of such difference could result in (i) an inability by the trust to make cash distributions in excess of applicable subordination thresholds with respect to a subsequent calendar quarter or (ii) distributions in excess of the incentive thresholds for a prior calendar quarter notwithstanding the fact that such shortfall or excess, respectively, would not have existed had production payments owed to the trust been calculated on an actual cash basis.
     The amount of available funds for distribution each quarter will be payable to the trust unitholders of record on or about the 45th day following the end of such calendar quarter or such later date as the Trustee determines is required to comply with legal or stock exchange requirements. The Trustee expects to distribute cash on or about the 60th day (or the next succeeding business day following such day if such day is not a business day) following such calendar quarter to each person who was a trust unitholder of record on the quarterly record date.
     Unless otherwise advised by counsel or the IRS, the Trustee will treat the income and expenses of the Trust for each month as belonging to the trust unitholders of record on the first business day of the month.
TRANSFER OF TRUST UNITS
     Trust unitholders may transfer their trust units in accordance with the trust agreement. The Trustee will not require either the transferor or transferee to pay a service charge for any transfer of a trust unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of any trust unit as shown by its records as the owner of the trust unit. The Trustee will not be considered to know about any claim or demand on a trust unit by any party except the record owner. A person who acquires a trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law will govern all matters affecting the title, ownership or transfer of trust units.
PERIODIC REPORTS
     The Trustee will file all required trust federal and state income tax and information returns. The Trustee will prepare and mail to trust unitholders a Schedule K-1 that trust unitholders need to correctly report their share of the income and deductions of the trust. The Trustee will also cause to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading.
     Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours, the records of the trust.

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LIABILITY OF TRUST UNITHOLDERS
     Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
VOTING RIGHTS OF TRUST UNITHOLDERS
     The Trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The Trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned.
     Unless otherwise required by the trust agreement, a matter may be approved or disapproved by the vote of a majority of the trust units held by the trust unitholders at a meeting where there is a quorum. This is true, even if a majority of the total outstanding trust units did not approve it. The affirmative vote of the holders of a majority of the outstanding trust units is required to:
    dissolve the trust (except in accordance with its terms);
 
    remove the Trustee or the Delaware Trustee;
 
    amend the trust agreement, the royalty conveyances, the Administrative Services Agreement, the Development Agreement, the Drilling Support Lien, the Royalty Interest Lien and the hedge agreements (except with respect to certain matters that do not adversely affect the right of trust unitholders in any material respect);
 
    merge or consolidate the trust with or into another entity; or
 
    approve the sale of all or any material part of the assets of the trust.
except that if any of the matters listed above (except removal of the Trustee or the Delaware Trustee) would result in a materially disproportionate benefit to ECA or its affiliates compared to other owners of common units, the affirmative vote of the holders of a majority of common units and a majority of trust units is required.
     In addition, certain amendments to the trust agreement may be made by the Trustee without approval of the trust unitholders. The Trustee must consent before all or any part of the trust assets can be sold except in connection with the dissolution of the trust or limited sales directed by ECA in conjunction with its sale of Royalties.
COMPARISON OF TRUST UNITS AND COMMON STOCK
     Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the Trustee.
     Unitholders should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.
         
    Trust units   Common stock
Voting
  The trust agreement provides voting rights to trust unitholders to remove and replace (but not elect) the Trustee and to approve or disapprove major trust transactions.   Corporate statutes provide voting rights to stockholders of the corporation to elect directors and to approve or disapprove major corporate transactions.

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    Trust units   Common stock
Income Tax
  The trust is not subject to federal income tax; trust unitholders are subject to income tax on their allocable share of trust income, gain, loss and deduction.   Corporations are taxed on their income, and their stockholders are taxed on dividends.
 
       
Distributions
  Substantially all trust revenue is distributed to trust unitholders.   Stockholders receive dividends at the discretion of the board of directors.
 
       
Business and Assets
  The business of the trust is limited to specific assets with a finite economic life.   A corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand.
 
       
Fiduciary Duties
  To the extent provided in the trust agreement, the Trustee has limited its fiduciary duties in the trust agreement as permitted by the Delaware Statutory Trust Act so that it will be liable to unitholders only for fraud, gross negligence or acts or omissions constituting bad faith.   Officers and directors have a fiduciary duty of loyalty to stockholders and a duty to use due care in management and administration of a corporation.

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FEDERAL INCOME TAX CONSIDERATIONS
     This section is a discussion of the material tax considerations that may be relevant to prospective trust unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to ECA and the Trust, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Future changes in these authorities may cause the tax consequences to vary substantially from the consequences described below.
     The following discussion does not address all federal income tax matters affecting the Trust or the trust unitholders. Moreover, the discussion focuses on trust unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, taxpayers subject to the alternative minimum tax, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, the trust encourages each prospective trust unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of trust units.
     No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any matter affecting the trust or prospective trust unitholders. Instead, the Trust is relying on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the trust units and the prices at which trust units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the trust unitholders, and thus will be borne indirectly by the trust unitholders. Furthermore, the tax treatment of the Trust, or of an investment in the trust, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
     All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by ECA and the trust.
     For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a trust unitholder whose trust units are loaned to a short seller to cover a short sale of trust units (please read “— Tax consequences of trust unit ownership — Treatment of short sales”); (2) whether the trust’s monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of trust units — Allocations between transferors and transferees”); and (3) whether percentage depletion will be available to a trust unitholder or the extent of the percentage depletion deduction available to any trust unitholder (please read “— Tax consequences of trust unit ownership — Tax treatment of the perpetual royalties”).
     As used herein, the term “trust unitholder” means a beneficial owner of trust units that for U.S. federal income tax purposes is:
    an individual who is a citizen of the United States or who is resident in the United States for U.S. federal income tax purposes,
 
    a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia,
 
    an estate the income of which is subject to U.S. federal income taxation regardless of its source, or

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    a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person.
     The term “non-U.S. trust unitholder” means any beneficial owner of a trust unit (other than an entity that is classified for U.S. federal income tax purposes as a partnership or as a “disregarded entity”) that is not a trust unitholder.
     If an entity that is classified for U.S. federal income tax purposes as a partnership is a beneficial owner of trust units, the tax treatment of a member of the entity will depend upon the status of the member and the activities of the entity. The trust encourages any entity that is classified for U.S. federal income tax purposes as a partnership and that is a beneficial owner of trust units, and the members of such an entity, to consult their own tax advisors about the U.S. federal income tax considerations of purchasing, owning, and disposing of trust units.
CLASSIFICATION OF THE TRUST AS A PARTNERSHIP
     Although the Trust is formed as a statutory trust under Delaware law, the Trust’s classification for federal income tax purposes is based on its characteristics rather than its form. Based on such characteristics, it is expected that, as described below, the Trust will be treated for federal and applicable state income tax purposes as a partnership and trust unitholders will be treated as partners in that partnership.
     A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss, deduction and credit of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest as of the end of the taxable year in which the distribution is made.
     Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, production and marketing of crude oil and natural gas and interest income (other than from a financial business). Other types of qualifying income include gains from the sale of real property and income from certain hedging transactions. The trust anticipates that substantially all of its gross income will be qualifying income. Based upon the factual representations made by the trust and ECA and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of the trust’s gross income will constitute qualifying income.
     No ruling has been or will be sought from the IRS and the IRS has made no determination as to the Trust’s status for federal income tax purposes or whether the Trust’s operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, the Trust is relying on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, Treasury Regulations, published revenue rulings and court decisions and the representations described below, the Trust will be classified as a partnership for federal income tax purposes.
     In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by the trust and ECA. The representations made by the trust and ECA upon which Vinson & Elkins L.L.P. has relied are:
      (a) The Trust has not, and will not, elect to be treated as a corporation;
      (b) The Trust is, and will be organized and operated in accordance with (i) all applicable trust statutes, including the Delaware Statutory Trust Act, (ii) the trust agreement, and (iii) the description thereof in this prospectus;
     (c) For each taxable year, more than 90% of the trust’s gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is qualifying income within the meaning of Section 7704(d) of the Internal Revenue Code; and

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     (d) Each hedging transaction that the trust treats as resulting in qualifying income will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and will be associated with oil, gas or products thereof that are held or will be held by the Trust in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.
     The Trust believes that these representations are true and expects that these representations will continue to be true in the future.
     If the Trust fails to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require the Trust to make adjustments with respect to the trust’s unitholders allocable share of trust income, gain, loss or deduction or pay other amounts), the Trust will be treated as if it had transferred all of its assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which the Trust fails to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in the Trust. This deemed contribution and liquidation should be tax-free to the trust unitholders and the Trust. Thereafter, the Trust would be treated as an association taxable as a corporation for federal income tax purposes.
     If the Trust were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, the trust’s items of income, gain, loss and deduction would be reflected only on the Trust’s tax return rather than being passed through to the trust unitholders, and the Trust’s net income would be taxed to the Trust at corporate rates. In addition, any distribution made to a trust unitholder would be treated as either taxable dividend income, to the extent of the Trust’s current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the trust unitholder’s tax basis in his trust units, or taxable capital gain, after the trust unitholder’s tax basis in his trust units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a trust unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the trust units.
     The discussion below is based on Vinson & Elkins L.L.P.’s opinion that the trust will be classified as a partnership for federal income tax purposes.
PARTNER STATUS
     Trust unitholders will be treated as partners of the Trust for federal income tax purposes. Also, trust unitholders whose trust units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their trust units will be treated as partners of the Trust for federal income tax purposes.
     A beneficial owner of trust units whose trust units have been transferred to a short seller to complete a short sale would appear, as a result, to lose his status as a partner with respect to those trust units for federal income tax purposes. Please read “— Tax consequences of trust unit ownership — Treatment of short sales.” Income, gain, deductions or losses would not appear to be reportable by a trust unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a trust unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to their tax considerations related to holding trust units. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in the Trust for federal income tax purposes.
TAX CLASSIFICATION OF THE PDP ROYALTY INTEREST AND THE PUD ROYALTY INTEREST
     For federal income tax purposes, a mineral interest similar to the PDP Royalty Interest and the PUD Royalty Interest will have the tax characteristics of a mineral royalty interest to the extent, at the time of its creation, such mineral interest is reasonably expected to have an economic life that corresponds substantially to the economic life of the mineral property or properties burdened thereby. Payments out of production that are received in respect of a mineral interest that constitutes a royalty interest for federal income tax purposes are taxable under current law as ordinary income subject to an allowance for cost or percentage depletion in respect of such income.

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     In contrast, a mineral interest similar to the PDP Royalty Interest and the PUD Royalty Interest will have the tax characteristics of production payments governed by Section 636 of the Internal Revenue Code to the extent, at the time of their creation, such a mineral interest is not reasonably expected to extend in substantial amounts over the entire productive life of the mineral property or properties it burdens. Payments out of production that are received in respect of a mineral interest that constitutes a production payment for federal income tax purposes are treated under current law as consisting of a receipt of principal and interest on a nonrecourse debt obligation, with the interest component being taxable as ordinary income.
     In the event that a portion of a single royalty interest terminates by its terms prior to the point in time that the economically productive life of the burdened mineral property is substantially exhausted and the remaining portion continues to burden the property until its economically productive life is substantially exhausted, the federal income tax characteristics of the royalty interest are determined as if it comprised two separate interests, with the terminating portion being treated as a production payment and the continuing portion being treated as a royalty interest.
     Based on the reserve report described in the Initial Prospectus and representations made by ECA regarding the expected economic life of the Underlying Properties and the expected duration of the Term Royalties and the Perpetual Royalties, the Term PDP Royalty will and the Term PUD Royalty should be treated as “production payments” under Section 636 of the Internal Revenue Code, and thus as nonrecourse debt instruments of ECA for U.S. federal income tax purposes. The Perpetual PDP Royalty will and the Perpetual PUD Royalty should be treated as continuing, nonoperating economic interest in the nature of royalties payable out of production from the mineral interests they burden.
     Consistent with this characterization, ECA and the trust treat the Perpetual Royalties as mineral royalty interests for federal income tax purposes. In addition, ECA and the Trust treat the Term Royalties as debt instruments for U.S. federal income tax purposes subject to the Treasury Regulations applicable to contingent payment debt instruments (the “CPDI regulations”), and the trust has agreed to be bound by ECA’s application of the CPDI regulations, including ECA’s determination of the rate at which interest is deemed to accrue on such interests. The remainder of this discussion assumes that the Term Royalties are treated in accordance with that agreement and ECA’s determinations that the Perpetual Royalties are treated as mineral royalty interests. No assurance can be given that the IRS will not assert that such interests should be treated differently. Such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in trust units and could require a trust unitholder to accrue interest income at a rate different than the “comparable yield” described below. Please read “— Tax consequences of trust unit ownership — Tax treatment of the term royalties,” and “— Tax consequences of trust unit ownership — Tax treatment of the perpetual royalties.”
TAX CONSEQUENCES OF TRUST UNIT OWNERSHIP
     Flow-Through of Taxable Income
     As a partnership for federal income tax purposes, the Trust is not a taxable entity required to pay any federal income tax. Instead, each trust unitholder will be required to report on his income tax return his allocable share of the Trust’s income, gains, losses, deductions and credits without regard to whether the trust makes cash distributions to him. Consequently, the trust may allocate taxable income to a trust unitholder even if he has not received a cash distribution.
     Accounting Method and Taxable Year
     The Trust uses the year ending December 31 as its taxable year and the accrual method of accounting for federal income tax purposes. Each trust unitholder is required to include in income his share of the trust’s income, gain, loss, deduction and credit for the trust’s taxable year ending within or with his taxable year. In addition, a trust unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his trust units following the close of the Trust’s taxable year but before the close of his taxable year must include his share of the Trust’s income, gain, loss, deduction and credit in his taxable income for his taxable year, with the result that he is required to include in income for his taxable year his share of more than twelve months of the trust’s income, gain, loss, deduction and credit. Please read “— Disposition of trust units — Allocations between transferors and transferees.”

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     Basis of Trust Units
     A trust unitholder’s initial tax basis for his trust units is the amount he paid for the trust units. That basis will be increased by his share of the Trust’s income and gain and decreased, but not below zero, by distributions from the Trust, by the trust unitholder’s share of the Trust’s losses, if any, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate allocated share of the adjusted tax basis of the Perpetual Royalties, and by his share of the Trust’s expenditures that are not deductible in computing taxable income and are not required to be capitalized. Please read “— Disposition of trust units — Recognition of gain or loss.”
     Allocation of Income, Gain, Loss, Deduction and Credit
     In general, if the Trust has a net profit, the Trust’s items of income, gain, loss, deduction and credit will be allocated among the trust unitholders in accordance with their percentage interests in the Trust. At any time that distributions are made to the common units in excess of distributions to the subordinated trust units, or incentive distributions are made in respect of the subordinated trust units, gross income will be allocated to the recipients to the extent of these distributions. If the Trust has a net loss, that loss will be allocated first to the subordinated trust units to the extent of their positive capital accounts and thereafter to the trust unitholders in accordance with their percentage interests in the Trust.
     Specified items of the Trust’s income, gain, loss, deduction and credit will be allocated under Section 704(c) of the Internal Revenue Code to account for any difference between the tax basis and fair market value of any property treated as having been contributed to the Trust by ECA or certain of its affiliates that existed at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” These “Section 704(c) Allocations” are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax bases of Contributed Property, referred to in this discussion as the “Book-Tax Disparity.” Finally, although the Trust does not expect that its operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of the Trust’s income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.
     An allocation of items of the Trust’s income, gain, loss, deduction or credit, other than an allocation required by Section 704(c) of the Internal Revenue Code to eliminate the Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss, deduction or credit only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his interest in the trust, which will be determined by taking into account all the facts and circumstances, including:
    his relative contributions to the trust;
 
    the interests of all the partners in profits and losses;
 
    the interest of all the partners in cash flow; and
 
    the rights of all the partners to distributions of capital upon liquidation.
     Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “Disposition of trust units — Allocations between transferors and transferees,” allocations under the trust agreement will be given effect for federal income tax purposes in determining a trust unitholder’s share of an item of income, gain, loss, deduction or credit.
     Treatment of Trust Distributions
     Distributions by the Trust to a trust unitholder generally will not be taxable to the trust unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his trust units immediately before the distribution. The Trust’s cash distributions in excess of a unitholder’s tax basis (if any)

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generally will be considered to be gain from the sale or exchange of the trust units, taxable in accordance with the rules described under “— Disposition of trust units” below.
     Ratio of Taxable Income to Distributions
     The Trust estimates that a purchaser of trust units in this offering who owns those trust units through the record date for distributions for the period ending December 31, 2013, would be allocated, on a cumulative basis, an amount of federal taxable income for that period that would be approximately 65% or less of the cash distributed with respect to that period. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond the trust’s control. Further, the estimates were based on current tax law and tax reporting positions that the trust adopted and with which the IRS could disagree. Accordingly, the Trust cannot assure unitholders that these estimates will prove to be correct. The actual percentage of distributions that will correspond to taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the trust units.
     Tax Treatment of the Term Royalties
     Under the CPDI regulations, the Trust generally is required to accrue income on the Term Royalties which are treated as production payments, and therefore as nonrecourse debt obligations of ECA for federal income tax purposes, in the amounts described below.
     The CPDI regulations provide that the trust must accrue an amount of ordinary interest income for U.S. federal income tax purposes, for each accrual period prior to and including the maturity date of the debt instrument that equals:
    the product of (i) the adjusted issue price (as defined below) of the debt instrument as of the beginning of the accrual period; and (ii) the comparable yield to maturity (as defined below) of such debt instrument, adjusted for the length of the accrual period;
 
    divided by the number of days in the accrual period; and
 
    multiplied by the number of days during the accrual period that the trust held the debt instrument.
     The initial “issue price” of the debt instrument represented by each production payment held by the trust was the portion of the first price at which a substantial amount of the trust units was sold to the public, excluding sales to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers, that is allocable to the production payment based on the relative fair market value of the production payment to the other assets of the trust. The “adjusted issue price” of such a debt instrument is its initial issue price increased by any interest income previously accrued, determined without regard to any adjustments to interest accruals described below, and decreased by the projected amount of any payments scheduled to be made with respect to the debt instrument at an earlier time (without regard to the actual amount paid). The term “comparable yield” means the annual yield ECA would have been expected to pay, as of the initial issue date, on a fixed rate debt security with no contingent payments but with terms and conditions otherwise comparable to those of the debt instrument represented by the production payment.
     ECA and the Trust take the position that the comparable yield for each debt instrument held by the Trust is an annual rate of 10%, compounded semi-annually. The CPDI regulations require and ECA provided to the Trust, solely for determining the amount of interest accruals for U.S. federal income tax purposes, a schedule of the projected amounts of payments, which are referred to as projected payments, on the Term Royalties treated as debt instruments held by the Trust. These payments set forth on the schedule must produce a total return on such debt instruments equal to their comparable yield. Amounts treated as interest under the CPDI regulations are treated as original issue discount for all purposes of the Internal Revenue Code.
     As required by the CPDI regulations, for U.S. federal income tax purposes, the Trust must use the comparable yield and the schedule of projected payments as described above in determining the trust’s interest accruals, and the adjustments thereto described below, in respect of the debt instruments held by the Trust.

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     ECA’s determinations of the comparable yield and the projected payment schedule are not binding on the IRS and it could challenge such determinations. If it did so, and if any such challenge were successful, then the amount and timing of interest income accruals of the Trust would be different from those reported by the trust or included on previously filed tax returns by the trust unitholders.
     The comparable yield and the schedule of projected payments were not determined for any purpose other than for the determination for U.S. federal income tax purposes of the Trust’s interest accruals and adjustments thereof in respect of the debt instruments held by the Trust and do not constitute a projection or representation regarding the actual amounts payable to the Trust.
     For U.S. federal income tax purposes, the Trust is required under the CPDI regulations to use the comparable yield and the projected payment schedule established by ECA in determining interest accruals and adjustments in respect of the production payments. Pursuant to the terms of the conveyance, ECA and the Trust have agreed (in the absence of an administrative determination or judicial ruling to the contrary) to be bound by ECA’s determination of the comparable yield and projected payment schedule.
     If, during any taxable year, the Trust receives actual payments with respect to a debt instrument held by the Trust that in the aggregate exceed the total amount of projected payments for that taxable year, the trust will incur a “net positive adjustment” under the CPDI regulations equal to the amount of such excess. The Trust will treat a “net positive adjustment” as additional interest income for such taxable year.
     If the Trust receives in a taxable year actual payments with respect to a debt instrument held by the Trust that in the aggregate are less than the amount of projected payments for that taxable year, the trust will incur a “net negative adjustment” under the CPDI regulations equal to the amount of such deficit. This adjustment will (a) reduce the Trust’s interest income on the debt instrument held by the Trust for that taxable year, and (b) to the extent of any excess after the application of (a) give rise to an ordinary loss to the extent of the trust’s interest income on such debt instrument during prior taxable years, reduced to the extent such interest was offset by prior net negative adjustments. Any negative adjustment in excess of the amount described in (a) and (b) will be carried forward, as a negative adjustment to offset future interest income in respect of that debt instrument held by the Trust. If either of the Term Royalties is not treated as a production payment (and not otherwise as a debt instrument) for federal income tax purposes, the trust intends to take the position that its basis in the Term Royalty is recouped in proportion to the production from the Term Royalty.
     Neither the Trust nor the trust unitholders are entitled to claim depletion deductions with respect to the Term Royalties.
     Tax Treatment of the Perpetual Royalties
     The payments received by the Trust in respect of the Perpetual Royalties treated as mineral royalty interests for federal income tax purposes will be treated as ordinary income. Trust unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to such income. Although the Internal Revenue Code requires each trust unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying Perpetual Royalties for depletion and other purposes, the Trust will furnish each of the trust unitholders with information relating to this computation for federal income tax purposes. Each trust unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the Perpetual Royalties for depletion and other purposes.
     Percentage depletion is generally available with respect to trust unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the trust unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the trust unitholder from the property for each taxable year, computed without the depletion allowance. A trust unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the trust unitholder’s average daily production of domestic crude oil, or the natural gas equivalent,

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does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.
     In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a trust unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the trust unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.
     In addition to the limitations on percentage depletion discussed above, on February 14, 2011, the White House released President Obama’s budget proposal for the fiscal year 2012 (the “2012 Budget”). The 2012 Budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources effective in 2012. Specifically, the 2012 Budget proposes to repeal the deduction for percentage depletion with respect to oil and natural gas wells, in which case only cost depletion would be available. It is uncertain whether this or any other legislative proposals will ever be enacted and, if so, when any such proposal would become effective.
     Trust unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the trust unitholder’s allocated share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the trust unitholder’s share of the total adjusted tax basis in the property.
     The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the trust unitholders. Further, because depletion is required to be computed separately by each trust unitholder and not by the Trust, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the trust unitholders for any taxable year. The Trust encourages each prospective trust unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.
     Tax Treatment Upon Sale of the Perpetual Royalties at Termination Date
     The sale of the Perpetual Royalties by the Trust at or shortly after the Termination Date will generally give rise to long-term capital gain or loss to the trust unitholders for federal income tax purposes, except that any gain will be taxed at ordinary income rates to the extent of depletion deductions that reduced the trust unitholder’s adjusted basis in the Perpetual Royalties. Each trust unitholder will be responsible for calculating his gain or loss based on the difference between his pro-rata share of the amount realized on the sale by the Trust and his adjusted basis in the Perpetual Royalties, and if a gain is realized, the portion thereof taxable as ordinary income by reason of depletion deductions previously claimed by such trust unitholder. However, the trust intends to furnish each of the trust unitholders with information relating to this calculation for federal income tax purposes in connection with the final partnership tax return for the Trust.
     Limitations on Deductibility of Losses
     It is not anticipated that the Trust will generate losses. Nevertheless, should losses result, trust unitholders must consult their own tax advisors as to the applicability to them of loss limitation rules that could operate to limit the deductibility to a trust unitholder of his share of the Trust’s losses such as the basis limitation, the “at risk” rules and the passive loss rules. Special passive loss limitation rules apply with respect to publicly-traded partnerships.

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     Limitations on Interest Deductions
     The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:
    interest on indebtedness properly allocable to property held for investment;
 
    the Trust’s interest expense attributed to portfolio income; and
 
    the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
     The computation of a trust unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a trust unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest deduction limitation. In addition, the trust unitholder’s share of the trust’s portfolio income will be treated as investment income.
     Entity-Level Withholdings
     If the Trust is required or elects under applicable law to pay any federal, state, local or foreign income tax on behalf of any trust unitholder or any former trust unitholder, the trust is authorized to pay those taxes from its funds. That payment, if made, will be treated as a distribution of cash to the trust unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, the trust is authorized to treat the payment as a distribution to all current trust unitholders. The Trust is authorized to amend its trust agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of trust units. Payments by the trust as described above could give rise to an overpayment of tax on behalf of an individual trust unitholder in which event the trust unitholder would be required to file a claim in order to obtain a credit or refund.
     Treatment of Short Sales
     A trust unitholder whose trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those trust units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
    any of the trust’s income, gain, loss, deduction or credit with respect to those trust units would not be reportable by the trust unitholder;
 
    any cash distributions received by the trust unitholder as to those trust units would be fully taxable; and
 
    all of these distributions would appear to be ordinary income.
     Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a trust unitholder whose trust units are loaned to a short seller to cover a short sale of trust units; therefore, trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their trust units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of trust units — Recognition of gain or loss.”
     Alternative Minimum Tax
     Each trust unitholder will be required to take into account his distributive share of any items of the Trust’s income, gain, loss, deduction or credit for purposes of the alternative minimum tax. The current minimum tax rate

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for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective trust unitholders are urged to consult with their tax advisors as to the impact of an investment in trust units on their liability for the alternative minimum tax.
     Tax Rates
     Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
     The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a trust unitholder’s allocable share of the trust’s income and gain realized by a trust unitholder from a sale of trust units. The tax will be imposed on the lesser of (i) the trust unitholder’s net income from all investments, and (ii) the amount by which the trust unitholder’s adjusted gross income exceeds $250,000 (if the trust unitholder is married and filing jointly) or $200,000 (if the trust unitholder is not married).
     Section 754 Election
     The Trust made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit the trust to adjust a trust unit purchaser’s tax basis in the Trust’s assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price of trust units acquired from another trust unitholder. The Section 743(b) adjustment belongs to the purchaser and not to other trust unitholders. For purposes of this discussion, a trust unitholder’s inside basis in the trust’s assets will be considered to have two components: (1) his share of tax basis in the Trust’s assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.
     A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of the Trust’s assets immediately prior to the transfer. In such a case, as a result of the election, the transferee would have a higher tax basis in his share of the Trust’s assets for purposes of calculating, among other items, cost depletion deductions on the Perpetual Royalties, and his share of any gain on a sale of the Trust’s assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those trust units’ share of the aggregate tax basis of the Trust’s assets immediately prior to the transfer. Thus, the fair market value of the trust units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in the trust if it has a substantial built-in loss immediately after the transfer. Generally a built — in loss or a basis reduction is substantial if it exceeds $250,000.
     The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of the Trust’s assets and other matters. For example, the allocation of the Section 743(b) adjustment among the trust’s assets must be made in accordance with the Internal Revenue Code. The trust cannot assure unitholders that the determinations it makes will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in the Trust’s opinion, the expense of compliance exceed the benefit of the election, the Trust may seek permission from the IRS to revoke its Section 754 election. If permission is granted, a subsequent purchaser of trust units may be allocated more income than he would have been allocated had the election not been revoked.
     Initial Tax Basis and Amortization
     The initial tax basis of the portion of the PDP Royalty Interest treated as a royalty interest in minerals and the portion treated as a production payment, and the initial basis of the portion of the PUD Royalty Interest treated as a

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royalty interest in minerals and the portion treated as a production payment were effectively equal on a per-unit basis to the portion of the unit price allocated to each based on each such portion’s relative fair market value.
     The costs incurred in selling the trust units in connection with the initial public offering (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon the Trust’s termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by the trust, and as syndication expenses, which may not be amortized by the Trust. The underwriting discounts and commissions the Trust incurs will be treated as syndication expenses.
     Valuation and Tax Basis of the Trust’s Properties
     The federal income tax consequences of the ownership and disposition of trust units will depend in part on the Trust’s estimates of the relative fair market values, and the initial tax bases, of the Trust’s assets. Although the trust may from time to time consult with professional appraisers regarding valuation matters, the trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by trust unitholders might change, and trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
DISPOSITION OF TRUST UNITS
     Recognition of Gain or Loss
     Gain or loss will be recognized on a sale of trust units equal to the difference between the amount realized and the trust unitholder’s tax basis for the trust units sold. A trust unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received. The amount realized should be reduced by the unused net negative adjustments attributable to the trust units disposed of as described above under “— Tax Consequences of trust unit ownership — Tax treatment of the term royalties.” A trust unitholder’s adjusted tax basis in his trust units will be equal to the trust unitholder’s original purchase price for the trust units, increased by income and decreased by losses or deductions previously allocated to the trust unitholder and by distributions to the trust unitholder and depletion deductions claimed by the trust unitholder.
     Prior distributions from the Trust in excess of cumulative net taxable income for a trust unit that decreased a unitholder’s tax basis in that trust unit will, in effect, become taxable income if the trust unit is sold at a price greater than the trust unitholder’s tax basis in that trust unit, even if the price received is less than his original cost.
     Except as noted below, gain or loss recognized by a trust unitholder, other than a “dealer” in trust units, on the sale or exchange of a trust unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of trust units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2012 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables” the trust owns. The term “unrealized receivables” includes potential recapture items, including depletion recapture. Ordinary income attributable to unrealized receivables such as depletion recapture may exceed net taxable gain realized upon the sale of a trust unit and may be recognized even if there is a net taxable loss realized on the sale of a trust unit. Thus, a trust unitholder may recognize both ordinary income and a capital loss upon a sale of trust units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.
     The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of

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the Internal Revenue Code allow a selling trust unitholder who can identify trust units transferred with an ascertainable holding period to elect to use the actual holding period of the trust units transferred. Thus, according to the ruling discussed above, a trust unitholder will be unable to select high or low basis trust units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific trust units sold for purposes of determining the holding period of trust units transferred. A trust unitholder electing to use the actual holding period of trust units transferred must consistently use that identification method for all subsequent sales or exchanges of trust units. A trust unitholder considering the purchase of additional trust units or a sale of trust units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.
     Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
    a short sale;
 
    an offsetting notional principal contract; or
 
    a futures or forward contract with respect to the partnership interest or substantially identical property.
     Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
     Allocations Between Transferors and Transferees
     In general, the Trust’s taxable income and losses will be determined annually, will be allocated on a monthly basis and will be subsequently apportioned among the trust unitholders in proportion to the number of trust units owned by each of them as of the opening of the applicable exchange on which the trust units are then traded on the first business day of the month, which is referred to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of the Trust’s assets other than in the ordinary course of business will be allocated among the trust unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a trust unitholder transferring trust units may be allocated income, gain, loss and deduction realized after the date of transfer.
     Although simplifying conventions are contemplated by the Internal Revenue Code, and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee trust unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the trust unitholder’s interest, the Trust’s taxable income or losses might be reallocated among the trust unitholders. The Trust is authorized to revise its method of allocation between transferor and transferee trust unitholders, as well as trust unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
     A trust unitholder who owns trust units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of the Trust’s income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

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     Notification Requirements
     A trust unitholder who sells any of his trust units is generally required to notify the Trust in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of trust units who purchases trust units from another trust unitholder is also generally required to notify the trust in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, the Trust is required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify the Trust of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who affects the sale or exchange through a broker who will satisfy such requirements.
     Constructive Termination
     The Trust will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in the Trust’s capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of the Trust’s taxable year for all trust unitholders. In the case of a trust unitholder reporting on a taxable year other than a calendar year, the closing of the Trust’s taxable year may result in more than twelve months of the Trust’s taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in the trust filing two tax returns (and trust unitholders may receive two Schedule K-1’s) for one fiscal year and the cost of the preparation of these returns will be borne by all trust unitholders. The IRS has recently announced a relief procedure whereby the IRS may permit a publicly traded partnership that has constructively terminated to provide only a single Schedule K-1 to unitholders for the tax years in which termination occurs. The Trust would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code. A termination could also result in penalties if the trust was unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject the Trust to, any tax legislation enacted before the termination.
     TAX EXEMPT ORGANIZATIONS AND OTHER INVESTORS
     Ownership of trust units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If a potential investor is a tax-exempt entity or a non-U.S. person, then it should consult a tax advisor before investing in the trust units.
Tax Exempt Organizations
     Employee benefit plans and most other organizations exempt from federal income tax including IRAs and other retirement plans are subject to federal income tax on unrelated business taxable income. Because all of the income of the trust is expected to be royalty income, interest income, hedging income and gain from the sale of real property, none of which is unrelated business taxable income, any such organization exempt from federal income tax is not expected to be taxable on income generated by ownership of trust units so long as neither the property held by the trust nor the trust units are debt-financed property within the meaning of Section 514(b) of the Internal Revenue Code. In general, trust property would be debt-financed if the trust incurs debt to acquire the property or otherwise incurs or maintains a debt that would not have been incurred or maintained if the property had not been acquired and a trust unit would be debt-financed if the trust unitholder incurs debt to acquire the trust unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if the trust unit had not been acquired. All or a portion of the floor hedging income may be treated as debt financed income treated as unrelated business taxable income.
     Non-U.S. Persons
     The Trust (or the appropriate intermediary if units are held in “street name”) will be required to withhold (at a 30% rate or lower applicable treaty rate) on interest and royalty income allocable to non-U.S. trust unitholders.
     Moreover, each of the PDP and PUD Royalty Interests will be treated as a “United States real property interest” for U.S. federal income tax purposes. However, as long as the trust units are regularly traded on an established

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securities market, gain realized by a non-U.S. trust unitholder on a sale of trust units will be subject to federal income tax only if:
    the gain is, or is treated as, effectively connected with business conducted by the non-U.S. trust unitholder in the United States, and in the case of an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by the non-U.S. trust unitholder;
 
    the non-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale and certain other conditions are met; or
 
    the non-U.S. trust unitholder owns currently, or owned at certain earlier times, directly or by applying certain attribution rules, more than 5% of the trust units.
ADMINISTRATIVE MATTERS
     Trust Information Returns and Audit Procedures
     The Trust intends to furnish to each trust unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of the trust’s income, gain, loss and deduction for the trust’s preceding taxable year. In preparing this information, which will not be reviewed by counsel, the Trust will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each trust unitholder’s share of income, gain, loss and deduction. The Trust cannot assure unitholders that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither the trust nor Vinson & Elkins L.L.P. can assure prospective trust unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
     The IRS may audit the Trust’s federal income tax information returns. Adjustments resulting from an IRS audit may require each trust unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a trust unitholder’s return could result in adjustments not related to the Trust’s returns as well as those related to the Trust’s returns.
     Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The trust agreement names ECA as the trust’s Tax Matters Partner.
     The Tax Matters Partner has made and will make some elections on behalf of the trust and the trust unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against trust unitholders for items in the trust’s returns. The Tax Matters Partner may bind a trust unitholder with less than a 1% profits interest in the trust to a settlement with the IRS unless that trust unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the trust unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any trust unitholder having at least a 1% interest in profits or by any group of trust unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each trust unitholder with an interest in the outcome may participate.
     A trust unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on the trust’s return. Intentional or negligent disregard of this consistency requirement may subject a trust unitholder to substantial penalties.
     Nominee Reporting
     Persons who hold an interest in the Trust as a nominee for another person are required to furnish to the trust:

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  (a)   the name, address and taxpayer identification number of the beneficial owner and the nominee;
 
  (b)   whether the beneficial owner is:
  1.   a person that is not a United States person;
 
  2.   a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
 
  3.   a tax-exempt entity;
  (c)   the amount and description of units held, acquired or transferred for the beneficial owner; and
     (d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers and acquisition cost for purchases, as well as the amount of net proceeds from sales.
     Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to the trust. The nominee is required to supply the beneficial owner of the trust units with the information furnished to the Trust.

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STATE TAX CONSIDERATIONS
     The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust unitholders. Trust unitholders are urged to consult their own legal and tax advisors with respect to these matters.
     Prospective investors should consider state and local tax consequences of an investment in the common units. The trust owns the Royalties burdening specified gas properties located in Greene County, Pennsylvania. The state of Pennsylvania has income taxes applicable to individuals, but currently does not require the trust to withhold taxes from distributions made to nonresident unitholders. If withholding were required under current Pennsylvanian law, the rate would be 3.07% of taxable income attributable to Pennsylvania. A trust unitholder may be required to file state income tax returns and/or pay taxes in Pennsylvania and may be subject to penalties for failure to comply with such requirements. Taxes withheld by the trust would be treated as deductions against state income taxes otherwise payable.
     The trust units may constitute real property or an interest in real property under the inheritance, estate and probate laws of Pennsylvania.

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ERISA CONSIDERATIONS
     The Employee Retirement Income Security Act of 1974, as amended, regulates pension, profit-sharing and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Internal Revenue Code provides similar requirements and standards which are applicable to qualified plans, which include these types of plans, and to individual retirement accounts, whether or not subject to ERISA.
     A fiduciary of a qualified plan should carefully consider fiduciary standards under ERISA regarding the qualified plan’s particular circumstances before authorizing an investment in trust units. A fiduciary should consider:
    whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA;
 
    whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and
 
    whether the investment is in accordance with the documents and instruments governing the qualified plan as required by Section 404(a)(1)(D) of ERISA.
     A fiduciary should also consider whether an investment in common units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Internal Revenue Code Section 4975. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. The Department of Labor has published final regulations concerning whether or not a qualified plan’s assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Internal Revenue Code. These regulations provide that the underlying assets of an entity will not be considered “plan assets” if the equity interests in the entity are a publicly offered security. ECA expects that at the time of the sale of the trust units in this offering, they will be publicly offered securities. Fiduciaries, however, will need to determine whether the acquisition of trust units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Internal Revenue Code Section 4975.
     The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential qualified plan investors should consult with their counsel to determine the consequences under ERISA and the Internal Revenue Code of their acquisition and ownership of trust units.

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SELLING TRUST UNITHOLDERS
     This prospectus covers the offering for resale or transfer of up to 3,001,733 common units by ECA. ECA acquired its units on July 7, 2010 at the formation and initial public offering of the trust. The trust is registering the common units described below pursuant to a registration rights agreement entered into by the Trust, ECA and certain affiliates in connection with such transaction.
     No offer or sale may be made except by ECA. ECA may sell all, some or none of the common units covered by this prospectus. Please read “Underwriting and Plan of Distribution.” ECA will bear all costs, fees and expenses incurred in connection with the registration of the common units offered by this prospectus. Brokerage commissions and similar selling expenses, if any, attributable to the sale of common units will be borne by the selling trust unitholder.
     No such sales may occur unless this prospectus has been declared effective by the SEC, and remains effective at the time such selling trust unitholder offer or sells such common units. We are required to update this prospectus to reflect material developments in our business, financial position and results of operations.
     The following table provides information regarding the selling trust unitholders’ ownership of the trust units.
                                 
                    Number of     Ownership of Trust  
    Ownership of Trust Units Before Offering     Common Units     Units following  
Selling Trust Unitholder   Number     Percentage     Being Offered     this Offering  
Energy Corporation of America
    7,402,983       42.1 %     3,001,733 (1)     4,401,250 (2)
 
(1)   In connection with this offering, 116,010 common units are being conveyed by ECA to certain eligible employees. Please read “Underwriting — Employee Incentive Units.”
 
(2)   Such units are subordinated units, which will automatically convert into common units on a one-for-one basis and ECA’s right to receive incentive distributions and to recoup the Reimbursement Amount will terminate, at the end of the fourth full calendar quarter following ECA’s satisfaction of its drilling obligation to the trust.

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UNDERWRITING AND PLAN OF DISTRIBUTION
     Subject to the terms and conditions in an underwriting agreement dated March  , 2011, the underwriters named below, for whom Citigroup Global Markets Inc. is acting as representative, have severally agreed to purchase from ECA the number of common units set forth opposite their names:
         
    Number of  
Name of Underwriter   Common Units  
Citigroup Global Markets Inc.
       
Oppenheimer & Co. Inc.
       
RBC Capital Markets, LLC
       
 
     
Total
    2,525,000  
     The underwriting agreement provides that the obligations of the underwriters to purchase and accept delivery of the common units offered by this prospectus are subject to the satisfaction of the conditions contained in the underwriting agreement, including:
    the representations and warranties made by ECA to the underwriters are true;
 
    there is no material adverse change in the financial market; and
 
    ECA and the Trust deliver customary closing documents and legal opinions to the underwriters.
     The underwriters are obligated to purchase and accept delivery of all of the trust units offered by this prospectus, if any of the units are purchased, other than those covered by the option to purchase additional common units described below.
     The underwriters propose to offer the common units directly to the public at the public offering price indicated on the cover page of this prospectus and to various dealers at that price less a concession not in excess of $  per unit. If all of the common units are not sold at the public offering price, the underwriters may change the public offering price and other selling terms. The common units are offered by the underwriters as stated in this prospectus, subject to receipt and acceptance by them. The underwriters reserve the right to reject an order for the purchase of the common units in whole or in part.

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OPTION TO PURCHASE ADDITIONAL COMMON UNITS
     ECA has granted the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase from time to time up to an aggregate of 360,723 additional common units to cover over-allotments, if any, at the public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus. If the underwriters exercise this option, each underwriter, subject to certain conditions, will become obligated to purchase its pro rata portion of these additional units based on the underwriters’ percentage purchase commitment in this offering as indicated in the table above. The underwriters may exercise the option to purchase additional common units only to cover over-allotments made in connection with the sale of the common units offered in this offering.
DISCOUNTS AND EXPENSES
     The following table shows the amount per unit and total underwriting discounts ECA will pay to the underwriters (dollars in thousands, except per unit). The amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.
                         
            Total without   Total with
            Over-   Over-
            Allotment   Allotment
    Per Unit   Exercise   Exercise
Public offering price
  $                    
Underwriting discount and commissions
  $                    
Proceeds to ECA (before expenses)
  $                    
INDEMNIFICATION
     ECA and the Trust have agreed to indemnify the underwriters and persons who control the underwriters against certain liabilities that may arise in connection with this offering, including liabilities under the Securities Act of 1933 and liabilities arising from breaches of representations and warranties contained in the underwriting agreement.
LOCK-UP AGREEMENTS
     Subject to specified exceptions (including the conveyence of the 116,010 common units to be conveyed to certain eligible employees) ECA and certain affiliates have agreed with the underwriters, for a period of 60 days after the date of this prospectus, without the prior written consent of Citigroup Global Markets Inc.:
    not to offer, sell, contract to sell, announce the intention to sell or pledge any of the trust units;
 
    not to grant or sell any option or contract to purchase any of the trust units;
 
    not to enter into any swap or other agreement that transfers any of the economic consequences of ownership of or otherwise transfer or dispose of, directly or indirectly, any of the trust units; and
 
    not to enter into any hedging, collar or other transaction or arrangement that is designed or reasonably expected to lead to or result in a transfer, in whole or in part, of any of the economic consequences of ownership of the trust units, whether or not such transfer would be for any consideration.
     These agreements also prohibit ECA from entering into any of the foregoing transactions with respect to any securities that are convertible into or exchangeable for the trust units.
     Citigroup Global Markets Inc. may, in its discretion and at any time without notice, release all or any portion of the securities subject to these agreements. Citigroup Global Markets Inc. does not have any present intent or any understanding to release all or any portion of the securities subject to these agreements.
     The 60-day period described in the preceding paragraphs will be extended if:
    during the last 17 days of the 60-day period, the trust issues an earnings release or announces material news or a material event relating to the trust occurs; or

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    prior to the expiration of the 60-day period, the trust announces that it will release earnings results during the 16-day period beginning on the last day of the 60-day period, in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release, the announcement of the material news or the occurrence of the material event.
STABILIZATION
     Until this offering is completed, rules of the SEC may limit the ability of the underwriters and various selling group members to bid for and purchase the common units. As an exception to these rules, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of the common units, including:
    short sales,
 
    syndicate covering transactions,
 
    imposition of penalty bids, and
 
    purchases to cover positions created by short sales.
     Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of the common units while this offering is in progress. Stabilizing transactions may include making short sales of common units, which involve the sale by the underwriters of a greater number of common units than it is required to purchase in this offering and purchasing common units from ECA or in the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.
     Each underwriter may close out any covered short position either by exercising its option to purchase additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, each underwriter will consider, among other things, the price of common units available for purchase in the open market compared to the price at which the underwriter may purchase common units pursuant to the option to purchase additional common units.
     A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market that could adversely affect investors who purchased in this offering. To the extent that the underwriters create a naked short position, they will purchase common units in the open market to cover the position.
     The underwriters also may impose a penalty bid on selling group members. This means that if the underwriters purchase common units in the open market in stabilizing transactions or to cover short sales, the underwriters can require the selling group members that sold those common units as part of this offering to repay the selling concession received by them.
     As a result of these activities, the price of the common units may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them without notice at any time. The underwriters may carry out these transactions on the New York Stock Exchange or otherwise.
CONFLICTS/AFFILIATES
     Certain of the underwriters and their affiliates may provide in the future investment banking, financial advisory or other financial services for ECA and its affiliates, for which they may receive advisory or transaction fees, as applicable, plus out-of-pocket expenses, of the nature and in amounts customary in the industry for these financial services.

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EMPLOYEE INCENTIVE UNITS
     ECA will convey 116,010 common units (“Employee Units”) to certain of its eligible employees as incentive compensation. ECA expects to deliver these units on or about 60 days following the closing of this offering. The Employee Units are included in this registration statement of which this prospectus is a part. The underwriters have not agreed and will not be obligated to purchase any Employee Units.
DISCRETIONARY ACCOUNTS
     The underwriters may confirm sales of the common units offered by this prospectus to accounts over which they exercise discretionary authority but do not expect those sales to exceed 5% of the total common units offered by this prospectus.
LISTING
     The common units are listed on the New York Stock Exchange under the symbol “ECT”.
ELECTRONIC PROSPECTUS
     A prospectus in electronic format may be available on the Internet sites or through other online services maintained by one or more of the underwriters and selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the underwriter or the selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with ECA to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.
     Other than the prospectus in electronic format, the information on any underwriter’s or any selling group member’s website and any information contained in any other website maintained by the underwriters or any selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by ECA or any underwriters or any selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
FINRA RULES
     Because the Financial Industry Regulatory Authority, or the “FINRA” is expected to view the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

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LEGAL MATTERS
     Richards, Layton & Finger, P.A., as special Delaware counsel to the trust, will give a legal opinion as to the validity of the trust units. Vinson & Elkins L.L.P., Houston, Texas, counsel to ECA, will give opinions as to certain other matters relating to the offering, including the tax opinion described in the section of this prospectus captioned “Federal income tax considerations.” Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.
EXPERTS
     Certain information appearing in this prospectus regarding the December 31, 2010 estimated quantities of reserves of the Royalties owned by the trust, the future net cash flows from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Ryder Scott Company, L.P., independent petroleum engineers.
     The statement of assets, liabilities and trust corpus as of December 31, 2010 and the related statements of distributable income and trust corpus for the period from inception (March 19, 2010) to December 31, 2010 of ECA Marcellus Trust I, appearing in this registration statement and prospectus have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.
WHERE YOU CAN FIND MORE INFORMATION
     The Trust has filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding the trust and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. The Trust’s registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.
     We intend to furnish the trust’s unitholders annual reports containing our audited consolidated financial statements and to furnish or make available to the trust’s unitholders quarterly reports containing the trust’s unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.
     The SEC allows the trust to “incorporate by reference” the information we have filed with the SEC. This means that we can disclose important information to you without actually including the specific information in this prospectus by referring you to other documents filed separately with the SEC. The information incorporated by reference is an important part of this prospectus.
     The trust incorporates by reference in this prospectus the following documents that it has previously filed with the SEC:
    The trust’s annual report on Form 10-K for the year ended December 31, 2010, as filed with the SEC on February 28, 2011;
     This report contains important information about the trust, its financial condition and our results of operations.

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     You may request a copy of any document incorporated by reference in this prospectus and any exhibit specifically incorporated by reference in those documents, at no cost, by writing or telephoning us at the following address or phone number:
ECA Marcellus Trust I
C/O The Bank of New York Mellon Trust Company, N.A., as Trustee
919 Congress Avenue
Austin, Texas 78701
1-800-852-1422

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS AND
TERMS RELATED TO THE TRUST
     In this prospectus the following terms have the meanings specified below.
     AMI — The area of mutual interest, or AMI, consists of the Marcellus Shale formation in approximately 121 square miles of property located in Greene County, Pennsylvania in which ECA had leased approximately 9,300 acres and owned substantially all of the working interests at the date of formation of the trust. ECA is obligated to drill the 52 development wells from drill sites on approximately 9,300 leased acres in the AMI. Until ECA has satisfied its drilling obligation, it will not be permitted to drill and complete any well in the Marcellus Shale formation within the AMI for its own account.
     Bbl— One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
     Bcf — One billion cubic feet of natural gas.
     Bcfe — One billion cubic feet of natural gas equivalent, with one barrel of crude oil being equivalent to six Mcf.
     Btu — A British Thermal Unit, a common unit of energy measurement.
     ECA’s retained interest — ECA’s retained interest in 10% of the proceeds from the sale of production from the 14 producing Marcellus Shale natural gas wells located in Greene County, Pennsylvania as well as ECA’s retained interest in 50% of the proceeds from the sale of production from the PUD Wells to be drilled in the AMI.
     Estimated future net revenues — Also referred to as “estimated future net cash flows.” The result of applying current prices of natural gas to estimated future production from natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.
     Farmout agreement — A farmout agreement is typically an agreement under which a lessee under an oil and gas lease agrees to grant to another party the right to drill wells on the tract covered by such lease and to earn certain acreage for drilling such wells.
     Fractional well — The fraction (either greater than one or less than one) of a well obtained by dividing the horizontal lateral (measured from the midpoint of the curve) of such well by 2,500 feet (subject to a maximum of 3,500 feet).
     Initial Prospectus — The prospectus dated July 1, 2010 and filed with the SEC pursuant to Rule 424(b) on July 1, 2010 relating to the initial public offering of the trust units.
     MBbl — One thousand barrels of crude oil, condensate or natural gas liquids.
     Mcf — One thousand cubic feet of natural gas.
     Mcfe — One thousand cubic feet of natural gas equivalent, with one barrel of crude oil being equivalent to six Mcf.
     MMBtu — One million British Thermal Units.
     MMcf — One million cubic feet of natural gas.
     MMcfe — One million cubic feet of natural gas equivalent, with one barrel of crude oil being equivalent to six Mcf.
     Net Profits Interest — A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

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     PDP Royalty Interest — Royalty interests entitling the trust to receive an aggregate of 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to, as of April 30, 2010, ECA’s working interest in the eight horizontal wells producing from the Marcellus Shale formation together with six additional wells that were undergoing completion operations and the last of which was turned online on August 27, 2010 (“Producing Wells”), for 20 years and 45% of such proceeds thereafter (pending a sale thereof by the trust).
     Private Investors — the persons described as the “Private Investors” in the Initial Prospectus.
     Proved developed reserves — Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
     Proved reserves — Under SEC rules for fiscal years ending on or after December 31, 2009, proved reserves are defined as:
    Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
     Proved undeveloped reserves — Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
     PUD Royalty Interest — Royalty interests entitling the trust to receive an aggregate of 50% of the proceeds (net of post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in 52 horizontal Marcellus Shale natural gas wells to be drilled in the AMI for 20 years and 25% of such proceeds thereafter (pending a sale thereof by the trust).
     Tcf — One trillion standard cubic feet of natural gas.
     Working interest — The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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ECA MARCELLUS TRUST I
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To The Bank of New York Mellon Trust Company, N.A., as Trustee of
ECA Marcellus Trust I
     We have audited the accompanying statement of assets, liabilities, and trust corpus of ECA Marcellus Trust I (the Trust) as of December 31, 2010, and the related statements of distributable income and trust corpus for the period from inception (March 19, 2010) to December 31, 2010. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audit.
     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Trust’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by the Trustee, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
     As described in Note 3, the financial statements have been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.
     In our opinion, the statements referred to above present fairly, in all material respects, the financial position of ECA Marcellus Trust I as of December 31, 2010 and its distributable income for the period from inception (March 19, 2010) to December 31, 2010, on the basis of accounting described in Note 3.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 28, 2011

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ECA MARCELLUS TRUST I
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS
As of December 31, 2010
         
ASSETS:
       
Cash
  $ 398,324  
Royalty income receivable
    6,885,434  
Hedge proceeds receivable
    2,032,620  
Floor price contracts
    4,858,920  
Royalty interest in gas properties
    352,100,000  
Accumulated amortization
    (14,854,467 )
 
     
Net royalty interest in gas properties
    337,245,533  
 
     
Total Assets
  $ 351,420,831  
 
     
 
       
LIABILITIES AND TRUST CORPUS:
       
Liabilities:
       
Floor premiums payable
  $ 4,957,920  
Distributions payable to unitholders
    8,809,013  
Incentive distribution payable to ECA
     
Floor costs payable to ECA as:
       
Premium
     
Interest
     
Trust corpus; 13,203,750 common units and 4,401,250 subordinated units authorized and outstanding
    337,653,898  
 
     
Total Liabilities and Trust Corpus
  $ 351,420,831  
 
     
See notes to the financial statements.

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ECA MARCELLUS TRUST I
STATEMENT OF DISTRIBUTABLE INCOME
FOR THE PERIODS ENDED DECEMBER 31, 2010
                 
    (Audited)     (Unaudited)  
    From Inception     Three Months Ended  
Royalty income
  $ 16,925,157     $ 6,885,434  
Hedge proceeds
    5,746,831       2,302,920  
 
           
Net proceeds to Trust
  $ 22,671,988     $ 9,188,354  
General and administrative expense
    (1,038,388 )     (379,750 )
Interest income
    409       409  
 
           
Income available for distribution prior to cash reserves and incentive calculation
  $ 21,634,009     $ 8,809,013  
Cash reserves (withheld) released by Trustee
    (500,000 )      
 
           
Income available for distribution prior to incentive calculation
  $ 21,134,009     $ 8,809,013  
Less:
               
Incentive distribution to ECA
    58,688        
Floor cost reimbursement distribution to ECA as:
               
Premium
           
Interest
    58,688        
 
           
Distriibutable income available to unitholders
  $ 21,016,633     $ 8,809,013  
 
           
Distributable income per unit (13,203,750 common units and 4,401,250 subordinated units authorized and outstanding)
  $ 1.193     $ 0.500  
 
           
See notes to the financial statements.

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ECA MARCELLUS TRUST I
STATEMENT OF TRUST CORPUS
AS OF DECEMBER 31, 2010
         
Trust Corpus, Beginning of Period
  $ 10  
Issuance of trust units
    352,100,000  
Cash reserves
    500,000  
Distribution income
    21,016,633  
Distributions paid or payable to unitholders
    (21,009,278 )
Amortization of royalty interest in gas properties
    (14,854,467 )
Amortization of floor contracts
    (99,000 )
 
     
Trust Corpus, End of Period
  $ 337,653,898  
 
     
See notes to the financial statements.

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ECA MARCELLUS TRUST I
NOTES TO FINANCIAL STATEMENTS
FOR THE PERIODS ENDED DECEMBER 31, 2010
NOTE 1. Organization of the Trust
     ECA Marcellus Trust I is a Delaware statutory trust formed in March 2010 by Energy Corporation of America (“ECA”) to own royalty interests in fourteen producing horizontal natural gas wells producing from the Marcellus Shale formation, all of which are online and are located in Greene County, Pennsylvania (the “Producing Wells”) and royalty interests in 52 horizontal natural gas development wells to be drilled to the Marcellus Shale formation (the “PUD Wells”) within the “Area of Mutual Interest,” or “AMI”, comprised of approximately 9,300 acres held by ECA, of which it owns substantially all of the working interests, in Greene County, Pennsylvania. The effective date of the Trust was April 1, 2010; consequently, the Trust received the proceeds of production attributable to the PDP Royalty Interest from that date even though the PDP Royalty Interest was not conveyed to the Trust until the closing of the initial public offering on July 7, 2010. The total number of units the Trust is authorized to issue is 17,605,000 units, of which 13,203,750 are common units and 4,401,250 are subordinated units. The royalty interests were conveyed from ECA’s working interest in the Producing Wells and the PUD Wells limited to the Marcellus Shale formation (the “Underlying Properties”). The royalty interest in the Producing Wells (the “PDP Royalty Interest”) entitles the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells. The royalty interest in the PUD Wells (the “PUD Royalty Interest” and collectively with the PDP Royalty Interest, the “Royalty Interests”) entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells. Approximately 50% of the estimated natural gas production attributable to the Trust’s royalty interests has been hedged with a combination of floors and swaps through March 31, 2014. The floor price contracts were transferred to the Trust by ECA, while ECA entered into a back-to-back swap agreement with the Trust to provide the Trust with the benefit of swap contracts entered into between ECA and third parties. ECA will be entitled to recoup the costs of establishing the floor price contracts only if and to the extent cash available for distribution by the Trust exceeds certain levels.
     ECA is obligated to drill all of the PUD Wells by March 31, 2013; however, in the event of delays, ECA will have until March 31, 2014 to fulfill its drilling obligation. ECA has granted to the Trust a lien (the “Drilling Support Lien”) on ECA’s interest in the Marcellus Shale formation in the AMI (except the Producing Wells and any other wells which are already producing and not subject to the Royalty Interests) in order to secure the estimated amount of the drilling costs for the Trust’s interests in the PUD Wells. The amount obtained by the Trust pursuant to the Drilling Support Lien may not exceed $91 million. As ECA fulfills its drilling obligation over time, the total dollar amount that may be recovered will be proportionately reduced and the drilled PUD Wells will be released from the lien.
     The Trust is not responsible for any costs related to the drilling of development wells or any other development or operating costs. The Trust’s cash receipts in respect of the royalties will be determined after deducting post-production costs and any applicable taxes associated with the PDP and PUD Royalty Interests, and the Trust’s cash available for distribution will include cash receipts from its hedging contracts and will be reduced by Trust administrative expenses and expenses incurred as a result of being a publicly traded entity. Post-production costs will generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production costs on its Greene County Gathering System will be limited to $0.52 per MMBtu gathered until ECA has fulfilled its drilling obligation (the “Post-Production Services Fee”); thereafter, ECA may increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System. Generally, the percentage of production proceeds to be received by the Trust with respect to a well will equal the product of (i) the percentage of proceeds to which the Trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) ECA’s net revenue interest in the well. ECA on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the Trust will be entitled to receive on average 73.37% of the proceeds of production from the Producing Wells. With respect to a PUD Well, the conveyance related to the PUD

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Royalty Interest provides that the proceeds from the PUD Wells will be calculated on the basis that the underlying PUD Wells are burdened only by interests that in total would not exceed 12.5% of the revenues from such properties, regardless of whether the royalty interest owners are actually entitled to a greater percentage of revenues from such properties. As the applicable net revenue interest of a well is calculated by multiplying ECA’s percentage working interest in such well by the unburdened interest percentage (87.5%), assuming ECA owns a 100% working interest in a PUD Well, such well would have a minimum 87.5% net revenue interest. Accordingly, the Trust would be entitled to 43.75% of the production proceeds from such well. To the extent ECA’s working interest in a PUD well is less than 100%, the Trust’s share of proceeds would be proportionately reduced. Pursuant to the Development Agreement, however, ECA will only satisfy its drilling obligation when it has drilled 52 equivalent wells. Therefore, any reduction in production proceeds attributable to a PUD Well caused by ECA having less than a 100% working interest in the well will be offset by the requirement to drill additional wells to achieve a total of 52 equivalent wells.
     The Trust will make quarterly cash distributions of substantially all of its cash receipts, after deducting Trust administrative expenses and the costs incurred as a result of being a publicly traded entity, on or about 60 days following the completion of each quarter through (and including) the quarter ending March 31, 2030 (the “Termination Date”). The first quarterly distribution was made on August 31, 2010 to record unitholders as of August 16, 2010. The Trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. At the Termination Date, 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will revert automatically to ECA. The remaining 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will be sold, and the net proceeds will be distributed pro rata to the unitholders soon after the Termination Date. ECA will have a first right of refusal to purchase the remaining 50% of the royalty interests at the Termination Date.
     In order to provide support for cash distributions on the common units, ECA has agreed to subordinate 4,401,250 of the trust units it owns, which constitute 25% of the outstanding trust units. The subordinated units are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units which is at least equal to the applicable quarterly subordination threshold. However, if there is not sufficient cash to fund such a distribution on all trust units, the distribution with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. In exchange for agreeing to subordinate these trust units, and in order to provide additional financial incentive to ECA to perform its drilling obligation and operations on the Underlying Properties in an efficient and cost-effective manner, ECA is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Trust units in any quarter exceeds 150% of the subordination threshold for such quarter. ECA’s right to receive the incentive distributions will terminate upon the expiration of the subordination period.
     ECA incurred costs of approximately $5.0 million for floor price contracts that were transferred to the Trust. ECA is entitled to reimbursement for these expenditures plus interest accrued at 10% per annum only if and to the extent distributions to Trust unitholders would otherwise exceed the incentive threshold. This reimbursement will be deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the Trust unitholders.
     The subordinated units will automatically convert into common units on a one-for-one basis and ECA’s right to receive incentive distributions and to recoup the reimbursement amount will terminate, at the end of the fourth full calendar quarter following ECA’s satisfaction of its drilling obligation to the Trust. Accordingly, ECA bears the risk that it will not be partially or fully reimbursed for the floor price contracts transferred to the Trust. ECA currently expects that it will complete its drilling obligation on or before March 31, 2013 and that, accordingly, the subordinated units will convert into common units on or before March 31, 2014. In the event of delays, it will have until March 31, 2014 under its contractual obligation to drill all the PUD Wells, in which event the subordinated units would convert into common units on or before March 31, 2015. The period during which the subordinated units are outstanding is referred to as the “subordination period.”
     The business and affairs of the Trust are managed by The Bank of New York Mellon Trust Company, N.A. as Trustee. Although ECA operates all of the Producing Wells and substantially all of the PUD Wells, ECA has no ability to manage or influence the management of the Trust.

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NOTE 2. Basis of Presentation
     The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Without limiting the foregoing statement, the information furnished is based upon certain estimates of the revenues attributable to the Trust from natural gas production for the three month and inception to date periods ended December 31, 2010 and is therefore subject to adjustment in future periods to reflect actual production for the periods presented.
NOTE 3. Significant Accounting Policies
     The accompanying audited financial information has been prepared by the Trustee in accordance with the instructions to Form 10-K. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) because certain cash reserves may be established for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. Amortization of expired floor price contract premiums does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Amortization of the investment in overriding royalty interests calculated on a unit-of-production basis is charged directly to Trust Corpus. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty Trusts by the U.S. Securities and Exchange Commission as specified by FASB ASC Topic 932 Extractive Activities—Oil and Gas: Financial Statements of Royalty Trusts. Income determined on the basis of GAAP would include all expenses incurred for the period presented. However, the Trust serves as a pass-through entity, with expenses for depreciation, depletion, and amortization, interest and income taxes being based on the status and elections of the Trust unitholders. General and administrative expenses, production taxes or any other allowable costs are charged to the Trust only when cash has been paid for those expenses. In addition, the royalty interest is not burdened by field and lease operating expenses. Thus, the statement purports to show distributable income, defined as income of the Trust available for distribution to the Trust unitholders before application of those additional expenses, if any, for depreciation, depletion, and amortization, interest and income taxes. The revenues are reflected net of existing royalties and overriding royalties and have been reduced by gathering/post-production expenses.
Cash:
     Cash consists of highly liquid instruments with maturities at the time of acquisition of three months or less.
Use of Estimates in the Preparation of Financial Statements:
     The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue and Expenses:
     The Trust serves as a pass-through entity, with items of depletion, interest income and expense, and income tax attributes being based upon the status and election of the unitholders. Thus, the Statements of Distributable Income purport to show Income available for distribution before application of those unitholders’ additional expenses, if any, for depletion, interest income and expense, and income taxes.
     The Trust uses the accrual basis to recognize revenue, with royalty income recorded as reserves are extracted from the Underlying Properties and sold. Expenses are recognized when paid.
Royalty Interest in Gas Properties:
     The Royalty Interests in gas properties are assessed to determine whether their net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to Accounting Standards Codification 360, Property, Plant and Equipment (“ASC 360”). The Trust will determine if a writedown is necessary to its investment in the Royalty Interests in gas properties to the extent that total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. The Trust will then provide a writedown to the extent that the net capitalized costs exceed the fair value of the investment in net profits interests attributable to proved gas reserves of the Underlying

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Properties. Any such writedown would not reduce Distributable Income, although it would reduce Trust Corpus. No impairment in the Underlying Properties was recognized during the periods ended December 31, 2010. Significant dispositions or abandonment of the Underlying Properties are charged to Royalty Interests and the Trust Corpus.
     Amortization of the Royalty Interests in gas properties is calculated on a units-of-production basis, whereby the Trust’s cost basis in the properties is divided by Trust total proved reserves to derive an amortization rate per reserve unit. Such amortization does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.
     The conveyance of the Royalty Interests to the Trust was accounted for as a purchase transaction. The $352,100,000 reflected in the Statements of Assets, Liabilities and Trust Corpus as Royalty Interests in Gas Properties represents 17,605,000 Trust Units valued at $20.00 per unit. The carrying value of the Trust’s investment in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.
Accrued Interest Payable:
     Accrued interest payable to ECA by the Trust is calculated at 10% per annum on the outstanding balance of the floor contract premiums payable, but is not recorded by the Trust until paid. As of December 31, 2010, the amount of unrecorded accrued interest payable to ECA was $313,156.
NOTE 4. Commodity Hedges
     The Trust is exposed to risk fluctuations in energy prices in the normal course of operations. ECA conveyed to the Trust natural gas derivative floor price contracts and entered into a back-to-back swap agreement with the Trust which conveyed the benefit of certain swap agreements which ECA had previously entered into with third parties. The volumes covered by these agreements equate to approximately 50% of the estimated natural gas to be produced by the Trust properties through March 31, 2014. The swap contracts relate to approximately 7,500 MMBtu per day at a weighted average price of $6.78 per MMBtu for the period from April 1, 2010 through June 30, 2012. The price of the floor hedging contracts is $5.00 per MMBtu on a total volume of 11,268,000 MMBtu for the period from October 1, 2010 through March 31, 2014. The Trust uses the cash method to account for commodity contracts. Under this method, gains or losses associated with the contracts are recognized at the time the hedged production occurs. Hedge proceeds realized for the quarter and inception to date for the periods ended December 31, 2010 totalled $2,302,920 and $5,746,831, respectively. The fair market values of the commodity contracts are not included in the accompanying financial statements, as the statements are presented on a modified cash basis of accounting.
NOTE 5. Income Taxes
     The Trust is a Delaware statutory trust, which is taxed as a partnership for federal and state income taxes. Accordingly, no provision for federal or state income taxes has been made.
NOTE 6. Related Party Transactions
Trustee Administrative Fee:
     Under the terms of the trust agreement, the Trust pays an annual administrative fee of $150,000 to the Trustee, which may be adjusted beginning on the fifth anniversary of the Trust as provided in the trust agreement. These costs, as well as those to be paid to ECA pursuant to the Administrative Services Agreement referred to below, will be deducted by the Trust in the period paid. The Trustee waived its administrative fee for the quarter ended June 30, 2010, but does not intend to waive the fee for any other quarter.
Administrative Services Fee:
     The Trust entered into an Administrative Services Agreement with ECA that obligates the Trust to pay ECA each quarter an administrative services fee for accounting, bookkeeping and informational services to be performed by ECA on behalf of the Trust relating to the Royalties. The annual fee of $60,000 is payable in equal quarterly installments. After the completion of ECA’s drilling obligation, under certain circumstances, ECA and the Trustee

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each may terminate the Administrative Services Agreement at any time following delivery of notice no less than 90 days prior to the date of termination. ECA waived its administrative services fee for the quarter ended June 30, 2010, but does not intend to waive the fee for any other quarter.
Drilling Support Lien:
     As described in Note 1, ECA has granted to the Trust the Drilling Support Lien on ECA’s interest in the Marcellus Shale formation in the AMI (except the Producing Wells and any other wells which are already producing and not subject to the Royalty Interests) in order to secure the estimated amount of the drilling costs for the Trust’s interests in the PUD Wells. The Drilling Support Lien is limited to $91 million, and as ECA fulfills its drilling obligation over time, the total dollar amount is to be proportionately reduced. As of December 31, 2010, ECA had received a partial release of the Drilling Support Lien in the amount of approximately $16.9 million.
NOTE 7. Subsequent Events
     As of February 23, 2011, two additional PUD wells had been brought online by ECA that were producing 2,653 Mcf per day net to the Trust’s interest. Also, twelve additional PUD wells have been drilled and are undergoing or awaiting completion operations.
Supplemental Reserve Information (Unaudited):
     Information regarding estimates of the proved gas reserves attributable to the Trust are based on reports prepared by independent petroleum engineering consultants. Such estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission. Accordingly, the estimates were based on existing economic and operating conditions. Numerous uncertainties are inherent in estimating reserve volumes and values and such estimates are subject to change as additional information becomes available.
     The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.
     The standardized measure of discounted future net cash flows was determined based on reserve estimates prepared by the independent petroleum engineering consultants, Ryder Scott.
     The following table reconciles the estimated quantities of the proved natural gas reserves attributable to the Trust’s interest from inception of the Trust to December 31, 2010:
         
    Natural Gas  
    (Mmcf)  
Proved reserves:
       
Balance at Inception
    108,640  
 
     
Revisions of previous estimates
    (1,608 )
Production
    (4,583 )
 
     
December 31, 2010
    102,449  
Proved developed reserves:
       
December 31, 2010
    42,487  
 
     

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
     The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with the provisions of FASB ASC topic Extractive Activities—Oil and Gas. Future cash inflows were computed by applying prices at year end to estimated future production.
     The following is the standardized measure of discounted future net cash flows as of December 31, 2010 (in thousands):
         
    2010  
Future cash inflows
  $ 475,909  
Future production taxes
     
Future production costs
    (54,872 )
 
     
Future net cash flows before discount
    421,037  
10% discount to present value
    (189,795 )
 
     
Standardized measure of discounted future net cash flows related to proved oil and gas reserves(1)
  $ 231,242  
 
     
 
(1)   No provision for federal or state income taxes has been provided for in the calculation because taxable income is passed through to the unitholders of the Trust.
Changes in Standardized Measure of Discounted Future Net Cash Flows:
     The following schedule reconciles the changes from inception to December 31, 2010 in the standardized measure of discounted future net cash flows relating to proved reserves (in thousands):
         
    2010  
Standardized measure of discounted future net cash flows at inception of Trust
  $ 205,875  
Net proceeds to the Trust
    (22,672 )
Revisions of previous estimates
    (3,629 )
Accretion of discount
    20,587  
Net change in price and production cost
    37,682  
Other
    (6,601 )
 
     
Standardized measure of discounted future net cash flows at end of period
  $ 231,242  
 
     

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(RYDER SCOTT COMPANY LOGO)
December 20, 2010
ECA Marcellus Trust I
The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue
Suite 500
Austin, Texas 78701
Gentlemen:
     At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain royalty interests of ECA Marcellus Trust I as of December 31, 2010. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The results of our third party study, completed on December 20, 2010, are presented herein. The properties reviewed by Ryder Scott represent 100 percent of the total net proved gas reserves of ECA Marcellus Trust I.
     The estimated reserves and future net income amounts presented in this report, as of December 31, 2010 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

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SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain and Royalty Interests of
ECA Marcellus Trust I
As of December 31, 2010
                                 
    Proved  
    Developed              
    Producing     Non-Producing     Undeveloped     Total Proved  
Net Remaining Reserves
                               
 
                               
Gas—MMCF
    38,151       4,335       59,963       102,449  
 
                               
Income Data
                               
 
                               
Future Gross Revenue
  $ 177,224,127     $ 20,138,777     $ 278,545,731     $ 475,908,635  
 
                               
Deductions
    20,433,824       2,321,988       32,116,137       54,871,949  
 
                       
 
                               
Future Net Income (FNI)
  $ 156,790,303     $ 17,816,789     $ 246,429,594     $ 421,036,686  
 
                               
Discounted FNI @ 10%
  $ 88,223,682     $ 10,533,827     $ 132,484,986     $ 231,242,495  
     All gas volumes are reported on an as “sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.
     The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
     The future gross revenue is normally after the deduction of production taxes but in the State of Pennsylvania this is zero. For ECA Marcellus Trust I, the deductions only incorporate gas transportation costs since the Trust will own only a royalty interest. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Gas reserves account for the remaining 100 percent of total future gross revenue from proved reserves.
     The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates, which were also compounded monthly. These results are shown in summary form as follows.
         
    Discounted Future Net Income
Discount Rate   As of December 31, 2010
Percent   Total Proved
5
  $ 298,155,984  
8
  $ 253,886,536  
12
  $ 212,492,880  
15
  $ 189,752,408  
     The results shown above are presented for your information and should not be construed as our estimate of fair market value.

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Reserves Included in This Report
     The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
     The various reserve status categories are defined in the attachment to this report entitled “Petroleum Reserves Definitions.” The developed proved non-producing reserves included herein consist of the behind-pipe category.
     No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The gas volumes included herein do not attribute gas consumed in operations as reserves.
     Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At ECA Marcellus Trust I’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.
     Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The reserves included herein were estimated using deterministic methods.
     Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Moreover, estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
     ECA Marcellus Trust I’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include matters relating to drilling, production practices, environmental protection, pricing policies, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ from the estimated quantities.
     The estimates of reserves presented herein were based upon a detailed study of the properties in which ECA Marcellus Trust I as of December 31, 2010 owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
     The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The reserve evaluator must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data

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available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
     In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. All quantities of reserves within the same reserve category have the same level of uncertainty under the SEC definitions.
     Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or economic risks as previously noted herein.
     The reserves for the properties included herein were estimated by performance methods or by analogy. In general, reserves attributable to producing wells were estimated by performance methods such as decline curve analysis which utilized extrapolations of historical production through November, 2010. In certain cases, producing reserves were estimated by a combination of performance and analogy if there was inadequate historical performance data to establish a definitive trend and where the use of production performance data as the sole basis for the reserve estimates was considered to be inappropriate. Reserves attributable to non-producing and undeveloped reserves included herein were estimated by the analogy method which utilized all pertinent well and seismic data available through November, 2010.
     To estimate economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
     Energy Corporation of America has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future production and income, we have relied upon data furnished by Energy Corporation of America with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, completion and development costs, product prices based on the SEC regulations. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by Energy Corporation of America. We consider the assumptions, data, methods and procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves and future net revenues herein.
Future Production Rates
     Our forecasts of future production rates are based on historical performance from wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Energy Corporation of America.

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     The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates.
Hydrocarbon Prices
     The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
     Energy Corporation of America furnished us with the above mentioned average prices in effect on December 31, 2010. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area(s) included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
     The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Energy Corporation of America.
     In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.
                                 
                    Average     Average  
Geographic           Price     Benchmark     Realized  
Area   Product     Reference     Prices     Prices  
United States
  Gas   Henry Hub   $4.38/MMBTU   $4.65/MCF
     The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
Costs
     Operating costs for the leases and wells in this report are supplied by Energy Corporation of America and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
     Development costs were furnished to us by Energy Corporation of America and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. Energy Corporation of America’s estimates of zero abandonment costs after salvage value were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Energy Corporation of America’s estimate.
     Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been

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assured will definitely be drilled. Energy Corporation of America has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.
     Current costs used by Energy Corporation of America were held constant throughout the life of the properties.
     It should be noted that ECA Marcellus Trust I, which owns only a royalty interest, is only subject to the gas transportation costs and all other costs are paid by the working interest owners and for this analysis only impact the calculation of the economic limit of the properties.
Standards of Independence and Professional Qualification
     Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
     Ryder Scott actively participates in industry related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
     Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
     We are independent petroleum engineers with respect to ECA Marcellus Trust I as of December 31, 2010. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
     The professional qualifications of the undersigned, the technical person primarily responsible for evaluating the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
     The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by ECA Marcellus Trust I.
     We have provided ECA Marcellus Trust I with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by ECA Marcellus Trust I and the original signed report letter, the original signed report letter shall control and supersede the digital version.
     The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
     This report was prepared for the exclusive use and sole benefit of ECA Marcellus Trust I as of December 31, 2010 and may not be put to other use without our prior written consent for such use. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

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  Very Truly Yours,

RYDER SCOTT COMPANY,L..P.
TBPE Firm Registration No. F-1580
 
 
  /s/ LARRY T. NELMS    
  Larry T. Nelms, P.E. [SEAL]
  Managing Vice President   
 

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Professional Qualifications of Primary Technical Person
     The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Larry Thomas Nelms is the primary technical person responsible for the estimate of the reserves, future production and income.
     Nelms, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1983, is a Managing Senior Vice President and also serves as a member of the Board of Directors, responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Nelms served in a number of engineering positions with Dome Petroleum, Mizel Petro Resources and Exxon. For more information regarding Mr. Nelms’ geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.
     Nelms earned a Bachelor of Science degree in Mechanical Engineering from Mississippi State University in 1963 and a Master of Science from the University of New Mexico in 1965, and he is a registered Professional Engineer in the State of Colorado. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, where he serves as chairman of the Denver Section and also served for three years on the board of directors.
     As part of his 2009 continuing education hours, Nelms attended an internally presented 16 hours of formalized training as well as the day long 2009 RSC Reserves Conference forum, and a presentation at the Denver Section of SPEE by Dr. John Lee relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Nelms serves as the instructor of the PetroSkills course entitled “Oil & Gas Reserve Evaluation” for a period of four years.
     Based on his educational background, professional training and more than 25 years of practical experience in the estimation and evaluation of petroleum reserves, Nelms has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

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2,525,000 Common Units
Representing Beneficial Interests
ECA Marcellus Trust I
 
PRELIMINARY PROSPECTUS
           , 2011
 
Citi
Oppenheimer & Co.
RBC Capital Markets
 


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PART II
INFORMATION REQUIRED IN THE REGISTRATION STATEMENT
Item 13. Other Expenses Of Issuance And Distribution.
     Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee and the FINRA fee, the amounts set forth below are estimates.
         
SEC Registration fee
  $ 10,469  
FINRA Fee
  $ 9,518  
Printing and engraving expenses
  $ 50,000  
Fees and expenses of legal counsel
  $ 75,000  
Accounting fees and expenses
  $ 75,000  
Miscellaneous
  $ 5,013  
 
     
Total
  $ 225,000  
 
     
Item 14. Indemnification Of Directors And Officers.
     The trust agreement provides that the Trustee and its officers, agents and employees shall be indemnified from the assets of the trust against and from any and all liabilities, expenses, claims, damages or loss incurred by it individually or as Trustee in the administration of the trust and the trust assets, including, without limitation, any liability, expenses, claims, damages or loss arising out of or in connection with any liability under environmental laws, or in the doing of any act done or performed or omission occurring on account of it being Trustee or acting in such capacity, except such liability, expense, claims, damages or loss as to which it is liable under the trust agreement. In this regard, the Trustee shall be liable only for fraud or gross negligence or for acts or omissions in bad faith and shall not be liable for any act or omission of any agent or employee unless the Trustee has acted in bad faith or with gross negligence in the selection and retention of such agent or employee. The Trustee is entitled to indemnification from the assets of the trust and shall have a lien on the assets of the trust to secure it for the foregoing indemnification.
Item 15. Recent Sales Of Unregistered Securities.
     On June 30, 2010, the registration statement on Form S-1/S-3 (Registration No. 333-165833-01) filed by ECA and the Trust in connection with the initial public offering of the trust units was declared effective by the Securities and Exchange Commission. On July 7, 2010, the Trust issued 17,605,000 trust units to ECA and/or the Private Investors in exchange for the conveyances made by ECA of the interests described elsewhere in this Annual Report on Form 10-K. Immediately thereafter, ECA completed an initial public offering of units of beneficial interest in the Trust, selling 8,802,500 trust units. After completion of the closing transactions, but prior to exercise of the underwriters’ overallotment option relating to the initial public offering, ECA retained an ownership in 3,296,683 common units and 4,401,250 subordinated units, or 43.7% of the total trust units issued and outstanding. The sale of the trust units to ECA and to the Private Investors was exempt from registration by virtue of Section 4(2) of the Securities Act of 1933.
Item 16. Exhibits.
     The following documents are filed as exhibits to this registration statement:
         
Exhibit        
Number       Description
1.1***
    Form of Underwriting Agreement
3.1(1)
    Certificate of Trust of ECA Marcellus Trust I (Incorporated herein by reference to Exhibit 3.1 to Registration Statement on Form S-1 (Registration No. 333-165833)).

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Exhibit        
Number       Description
3.2*
      Amended and Restated Trust Agreement of ECA Marcellus Trust I, dated July 7, 2010, among Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee, and Corporation Trust Company, as Delaware Trustee (Incorporated herein by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)).
 
5.1****
    Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units
 
8.1****
    Opinion of Vinson & Elkins L.L.P. relating to tax matters
 
10.1*
    Perpetual Overriding Royalty Interest Conveyance (PDP), dated effective April 1, 2010, from Energy Corporation of America to The Bank of New York Mellon Trust Company, N.A., as Trustee.
 
10.2*
    Perpetual Overriding Royalty Conveyance (PUD), dated effective April 1, 2010, from Energy Corporation of America to The Bank of New York Mellon Trust Company, N.A., as Trustee.
 
10.3*
    Private Investor Conveyance, dated July 7, 2010, among ECA Marcellus Trust I and certain private investors named therein.
 
10.4*
    Assignment of Royalty Interest, dated effective April 1, 2010, from Eastern Marketing Corporation to The Bank of New York Mellon Trust Company, N.A., as Trustee.
 
10.5*
    Term Overriding Royalty Interest Conveyance (PDP), dated effective April 1, 2010 from Energy Corporation of America to Eastern Marketing Corporation.
 
10.6*
    Term Overriding Royalty Conveyance (PUD), dated effective April 1, 2010, from Energy Corporation of America to Eastern Marketing Corporation.
 
10.7*
    Administrative Services Agreement, dated July 7, 2010, between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee.
 
10.8*
    Development Agreement, dated July 7, 2010, between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee.
 
10.9*
    Swap Agreement, dated July 7, 2010, between Energy Corporation of America and ECA Marcellus Trust I.
 
10.10*
    Drilling Support Lien, dated July 7, 2010, by and between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee.
 
10.11*
    Royalty Interest Lien, dated July 7, 2010, by and between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee.
 
10.12*
    Registration Rights Agreement, dated July 7, 2010, by and among ECA Marcellus Trust I, Energy Corporation of America, and certain affiliates of Energy Corporation of America.
 
23.1****
    Consent of Ernst & Young LLP
 
23.2**
    Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1)
 
23.3**
    Consent of Vinson & Elkins, L.L.P. (contained in Exhibit 8.1)
 
23.4****
    Consent of Ryder Scott
 
(1)   Filed as Exhibit 3.1 to Registration Statement on Form S-1 (Registration No. 333-165833)
 
*   Exhibit previously filed with the SEC and incorporated herein by reference to the exhibit of like designation filed with the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800).
 
**   Filed herewith
 
***   To be filed by amendment
 
****   Previously filed with the Registration Statement on Form S-1 (Registration No. 333-172797) on March 14, 2011.
Item 17. Undertakings.
     The undersigned registrant hereby undertakes:
     (1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:
     i. To include any propectus required by section 10(a)(3) of the Securities Act of 1933;
     ii. To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement.
     iii. To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;
     (2) That for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
     (3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
     (4) For the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

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     (5) That for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:
     i. Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;
     ii. Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;
     iii. The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and
     iv. Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.
     (6) That for purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrants pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
     (7) That for the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
     The undersigned registrant hereby undertakes to deliver or cause to be delivered with the prospectus, to each person to whom the prospectus is sent or given, the latest annual report to security holders that is incorporated by reference in the prospectus and furnished pursuant to and meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Securities Exchange Act of 1934; and, where interim financial information required to be presented by Article 3 of Regulation S-X are not set forth in the prospectus, to deliver, or cause to be delivered to each person to whom the prospectus is sent or given, the latest quarterly report that is specifically incorporated by reference in the prospectus to provide such interim financial information.
     Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers, and controlling persons of the registrants pursuant to the foregoing provisions, or otherwise, the registrants have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrants of expenses incurred or paid by a director, officer or controlling person of a registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrants will, unless in the opinion of their respective counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by them is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

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SIGNATURES
     Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Austin, State of Texas, on March 25, 2011.
         
  ECA MARCELLUS TRUST I
 
 
  By:   The Bank of New York Mellon
Trust Company, N.A.  
 
 
 
  By:   /s/ Mike J. Ulrich  
    Name:   Mike J. Ulrich   
    Title:   Vice President  
 

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