ECA Marcellus Trust I - Annual Report: 2010 (Form 10-K)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

Commission File Number 001-34800

ECA Marcellus Trust I
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (800) 852-1422

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None
(Title of class)

          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý.

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý.

          Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

          Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

          Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

          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):

          Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o    No ý

          The aggregate market value of Units of Beneficial Interest in ECA Marcellus Trust I held by non-affiliates on June 30, 2010, the last business day of the registrant's most recently completed second fiscal quarter, is not applicable as the registrant's equity was not traded as of June 30, 2010.

          As of February 25, 2011, 13,203,750 Common Units and 4,401,250 Subordinated Units of Beneficial Interest in ECA Marcellus Trust I were outstanding.

Documents Incorporated By Reference: None

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        References to the "Trust" in this document refer to ECA Marcellus Trust I. References to "ECA" in this document refer to Energy Corporation of America and its wholly-owned subsidiaries, and when discussing the conveyance documents, the Private Investors.

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FORWARD-LOOKING STATEMENTS

        This Form 10-K contains "forward-looking statements" about ECA and the Trust and other matters discussed herein that are subject to risks and uncertainties. All statements other than statements of historical fact included in this document, including, without limitation, statements under "Trustee's Discussion and Analysis of Financial Condition and Results of Operations" and "Risk Factors" regarding the financial position, business strategy, production and reserve growth, development activities and costs and other plans and objectives for the future operations of ECA and all matters relating to the Trust are forward-looking statements. Actual outcomes and results may differ materially from those projected.

        When used in this document, the words "believes," "expects," "anticipates," "intends" or similar expressions, are intended to identify such forward-looking statements. Further, all statements regarding future circumstances or events are 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;



•

conditions in the capital markets;



•

competition from others in the energy industry;



•

the uncertainty of estimates of natural gas reserves and production; and



•

other risks described under the caption "Risk Factors" in this Report on Form 10-K.

        This Form 10-K describes other important factors that could cause actual results to differ materially from expectations of ECA and the Trust, including under the caption "Risk Factors." All subsequent 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. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.

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GLOSSARY OF CERTAIN TERMS

        In this report the following terms have the meanings specified below. Other terms are defined in the text of this report.

        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).

        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.

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        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.

        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 Prospectus.

        "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.

        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.

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        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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PART I

Item 1.    Business

Introduction

        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 Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee"). The Trust maintains its offices at the office of the Trustee, at 919 Congress Avenue, Austin, Texas 78701. The telephone number of the Trustee is 1-800-852-1422.

        The Trust makes copies of its reports under the Exchange Act available at www.businesswire.com/cnn/ect.htm. The Trust's filings under the Exchange Act are also available electronically from the website maintained by the Securities and Exchange Commission ("SEC") at http://www.sec.gov. The Trust will also provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.

General

        The Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Royalties (described below), and to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalties after the payment of Trust expenses. The Trustee performs certain administrative functions in respect of the Royalties and the Trust units. The Trust derives all or substantially all of its income and cash flows from the Royalties, which in turn are subject to the hedge contracts described in this report. The Trust is treated as a partnership for federal income tax purposes.

        Initially, the Trust owned royalty interests in the 14 Producing Wells described in the Prospectus (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", in which ECA presently holds approximately 9,300 acres, of which it owns substantially all of the working interests, in Greene County, Pennsylvania. The Area of Mutual Interest consists of the Marcellus Shale formation in approximately 121 square miles in Greene County, Pennsylvania.

        As of December 31, 2010, six PUD Wells were online and producing and two PUD Wells were completed but awaiting initial production. Accordingly, as of December 31, 2010, the Trust owned royalty interests in twenty producing horizontal natural gas wells producing from the Marcellus Shale formation and located in Greene County, Pennsylvania, royalty interests in two PUD Wells completed but awaiting initial production and royalty interests in the remaining horizontal natural gas development wells to be drilled to the Marcellus Shale formation. ECA is obligated to drill the remaining 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 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 for a period of 20 years commencing on April 1, 2010 and 45% thereafter. The royalty interest in the PUD Wells (the "PUD Royalty Interest" and together 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 for a period of 20 years

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commencing on April 1, 2010 and 25% thereafter. As used herein, the term "Producing Wells" means the 14 Producing Wells as defined above, and does not include PUD Wells, even though some or all of the PUD Wells may have been drilled and completed and may be producing. 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.

        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. As of December 31, 2010, ECA had drilled 16.29 of the PUD Wells, calculated as provided in the Development Agreement. 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 is determined after deducting post-production costs and any applicable taxes associated with the PDP and PUD Royalty Interests. The Trust's cash available for distribution includes any cash receipts from the Hedge Contracts and is 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 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 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.

Target Distributions and Subordination and Incentive Thresholds

        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.

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        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 transferred to the Trust; and



•

administrative expenses of the Trust and expenses incurred as a result of being a publicly traded entity, and any changes in amounts reserved for such expenses.

        The amount of the quarterly distributions will fluctuate from quarter to quarter, depending on the proceeds received by the Trust, among other factors. There is no minimum required distribution. However, 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. While the subordinated units will be 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 thresholds set forth below, 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. 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 transferred to the Trust. ECA is entitled to reimbursement for these expenditures plus interest accrued at 10% per annum ("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 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. 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 subordination and incentive thresholds for each calendar quarter through the first quarter of 2015. The effective date of the Trust is April 1, 2010, meaning it has

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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 July 7, 2010.

        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 and reserves therefore, 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 or about August 31, 2010 to record unitholders as of August 15, 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 life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent a return of the original investment in the Trust units.

        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

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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. 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.

The Administrative Services Agreement

        The Trust has 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, payable in equal quarterly installments, is $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 provision 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

        The Trust has entered into a Development Agreement with ECA which obligates ECA to drill all of the PUD Wells by March 31, 2013; however, 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 are already producing 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"). The original maximum amount of the Drilling Support Lien was $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.

        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 will 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 from 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 beyond the mid-point of the curve, the 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.

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        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.

        ECA has agreed not to drill and complete, and not to 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 has further agreed not to drill and complete, and not to 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.

Hedging Contracts Transferred to the Trust

        ECA has also transferred to the Trust natural gas derivative floor price contracts and entered into a back-to-back swap agreement with the Trust to provide the Trust with the benefit of certain contracts entered into between ECA and third parties that equate to approximately 50% of the estimated natural gas to be produced by the Trust properties 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 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.

Marketing and Post-Production Services

        Pursuant to the terms of the conveyances creating the Royalties, ECA will have the responsibility to market, or cause to be marketed, the natural gas production related to the Underlying Properties. The terms of the conveyances creating the Royalties do not permit ECA to charge any marketing fee

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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 from the Underlying Properties 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 from the Underlying Properties. 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 from the Underlying Properties.

        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 report 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.

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        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 from the Underlying Properties 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.

        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 for the Underlying Properties.

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.

Environmental Matters and Regulation

        The operations of the properties comprising the Underlying Properties are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

•

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;



•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;



•

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and

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•

enjoin some or all of the operations of the Underlying Properties deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

        Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, these laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on the operating costs of the properties comprising the underlying properties.

        The following is a summary of the existing laws, rules and regulations to which the operations of the properties comprising the underlying properties are subject that are material to the operation of the Underlying Properties.

        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 construction, 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 or costly construction, drilling, water withdrawal, 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 increased compliance costs to its customers. Moreover, accidental releases or spills may occur in the

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course of ECA's operations, and there can be no assurance that ECA will not incur significant costs 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, 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 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 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.

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        On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. These findings allow the EPA 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 regulations that could trigger permit review for GHG emissions from certain stationary sources. 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. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG gases 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 it produces. 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 assets and operations.

        More than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on ECA's business, 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. The Pennsylvania Department of Environmental Protection has adopted a new 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. 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.

        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 in 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. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. The Pennsylvania Environmental Quality Board has

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proposed 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. Any increased federal, state or local regulation could reduce the volumes of natural gas that ECA produces, which would materially adversely affect its revenues and results of operations. Moreover, in March 2010, the EPA announced that it has allocated $1.9 million in 2010 and has requested funding in fiscal year 2011 for conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The results of such a study, once completed, could further spur action towards federal legislation and regulation of hydraulic fracturing activities. An additional level of regulation and permitting of hydraulic fracturing operations at the federal level, could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult for ECA to perform hydraulic fracturing.

        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. The Pennsylvania Environmental Quality Board has proposed 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, that, if adopted in their proposed form, could require ECA to incur increased operating costs. 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.

        ECA believes that it is in substantial compliance with all existing environmental laws and regulations applicable to the current operations of the Underlying Properties and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. ECA did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2010 with respect to the Underlying Properties. Additionally, ECA has informed the Trust that ECA is not aware of any environmental issues or claims that will require material capital expenditures during 2011 with respect to the Underlying Properties. However, there is no assurance that the passage of more stringent laws or implementing regulations in the future will not have a negative impact on the operations of these properties and the cash distributions to the Trust unitholders.

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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 report. 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

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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.

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 Underlying Properties.

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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 Underlying Properties. Neither ECA nor other operators of the Underlying Properties 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 royalty 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 Trust is not able to issue any additional Trust units.

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;



•

causing to be prepared and distributed a Schedule K-1 for each Trust unitholder and preparing and filing 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.

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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. 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 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.

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.

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 will also be 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.

Duration of the Trust; Sale of Royalties

        The Trust will remain in existence until the Termination Date, which is March 31, 2030. The Trust will dissolve 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.

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Federal Income Tax Considerations

        The Trust's federal income tax reporting position is that it should be classified as a partnership for federal and applicable state income tax purposes. This position relies on the opinion of Vinson & Elkins L.L.P., counsel to ECA and the Trust rendered in connection with the initial public offering of the Trust Units, in which counsel opined that at least 90% of the Trust's gross income will be qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended. The Trust's federal income tax reporting positions are consistent with the Federal Income Tax Considerations section in the Trust's prospectus filed with the SEC pursuant to Rule 424(b) under the Securities Act of 1933, as amended, on July 1, 2010 in connection with the offering of its common units to the public (the "Federal Income Tax Considerations Section in the Prospectus"). However, as discussed in detail below under Item 1A. Risk Factors—Tax Risks Related to the Trust's Common Units, the Trust has not requested a ruling from the IRS regarding its United States federal income tax reporting positions and its positions may not be sustained by a court or if contested by the IRS.

        The material federal income tax considerations that may be relevant to certain Trust unitholders were discussed in the Federal Income Tax Considerations Section in the Prospectus. Unitholders and prospective unitholders should review the Prospectus.

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.

Item 1A.    Risk Factors

         Drilling and completion of the PUD Wells on the Underlying Properties 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 the following:

•

delays imposed by or resulting from compliance with regulatory requirements including permitting;



•

unusual or unexpected geological formations;

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•

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.

        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;

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•

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 Underlying Properties. See "The underlying properties—Natural gas reserves" of the 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:

•

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 less than 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

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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.

        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

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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 a preliminary title review on the PUD Wells. Prior to the drilling of a PUD Well, ECA intends to obtain a preliminary title review to ensure there are no obvious defects 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

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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 of the Trust 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 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

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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 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.

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•

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 distributions is set forth under the caption "Target Distributions and Subordination and Incentive Thresholds" in Item 1 of this report.



•

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 underlying properties" of the 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.

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         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 from April 1, 2010 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, 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

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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.

         Estimates of future cash distributions to unitholders, subordination thresholds and incentive thresholds are based on assumptions that are inherently subjective and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual cash distributions to differ materially from those estimated.

        The estimates of target distributions to unitholders, subordination thresholds and incentive thresholds, as set forth in Item 1 of this report 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 are 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.

        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.

        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 the Prospectus under the caption "The Trust."

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

        ECA holds an aggregate of 3,001,733 common units and 4,401,250 subordinated units. All of the subordinated units will automatically convert into common units at the end of the subordination period, which is currently expected to occur on April 1, 2014. ECA may sell Trust units in the public or private markets, and any such sales could have an adverse impact on the price of the common units or on any trading market that may develop. The Trust has granted registration rights to ECA which, if exercised, would facilitate sales of common units by such holders.

         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 "Sale and Abandonment of Underlying Properties" in Item 2 of this report.



•

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 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.

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•

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

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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 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 has proposed 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.

        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

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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. See "Information about Energy Corporation of America" found on page ECA-1 of the Prospectus for additional information relating to ECA, including information relating to the business of ECA, historical financial statements of ECA and other financial information relating to 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. 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

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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.

         ECA's performance of its drilling obligations to the Trust and the financial results of the Trust may not be as successful as the drilling and financial results of Eastern American Natural Gas Trust or ECA's other royalty interest ventures.

        As disclosed in the Prospectus, ECA previously sponsored the formation of Eastern American Natural Gas Trust, and ECA has previously sold term royalty interests in a separate transaction to private investors. The historical results of operations and performance of the Eastern American Natural Gas Trust should not be relied on as an indicator of how this Trust will perform.

         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 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.

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         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 regulations that could trigger permit review for GHG emissions from certain stationary sources. 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. At the state level, more than one-third 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 regulations imposing reporting obligations on, or 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. 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 April 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 has proposed 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. Moreover, the Pennsylvania Department of Environmental Protection has adopted a new 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 the any other federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process 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, on March 18, 2010, the EPA announced that it has allocated $1.9 million in 2010 and has requested funding in fiscal year 2011 for conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The results of such a study, once completed, could further spur action towards federal legislation and regulation of hydraulic fracturing

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activities. 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 our 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.

        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 the 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 reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of 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.

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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 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 recently introduced legislation that would have imposed a severance tax of 5% of the value of natural gas at the wellhead plus $0.046 per thousand 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 affect 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 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

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$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

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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 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.

Item 1B.    Unresolved Staff Comments.

        None.

Item 2.    Properties.

The Underlying Properties

        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 PDP Royalty Interest and the PUD Royalty Interest were conveyed. 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 42.5 BCF of proved developed reserves and 59.9 BCF of proved undeveloped reserves. ECA is currently the operator of all of the wells subject to the PDP Royalty Interest. 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 royalty interests as well as the residual interest in the reserves that the Trust will sell on or shortly following the Termination Date.

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        As of December 31, 2010, the Underlying Properties include 19 gross (19.5 net as calculated under the Development Agreement) productive gas wells which encompass approximately 1,520 gross (1,560 net as calculated under the Development Agreement) productive acres. Currently, the Underlying Properties include approximately 9,300 acres of which ECA owns substantially all of the working interests.

The Underlying PUD Properties

        The underlying PUD properties consist of all of the working interests in proved undeveloped gas properties in the AMI held by ECA. The interests of ECA in the gas properties to which the underlying PUD properties relate consist of working interests of approximately 100%. The conveyance related to the PUD Royalty Interest, however, provides that the proceeds from the PUD Wells will be calculated on the basis that the underlying PUD Wells are only burdened by interests that in total would not exceed 12.5% of the revenues from such properties, regardless of whether the other interest owners are actually entitled to a greater percentage of revenues from such properties. The AMI is located in Greene County, Pennsylvania, which is in southwestern Pennsylvania and consists of approximately 121 square miles.

        The PUD Royalty Interest entitles the Trust to receive an undivided 50% interest in the proceeds from the sale of future production of natural gas resulting from the drilling of the PUD Wells. As ECA drills the PUD Wells, the Trustee is required to release the Drilling Support Lien.

        ECA has 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 the lease acreage included within the AMI described above for its own account until such time as ECA has met its commitment to drill the PUD Wells. Upon the Trustee's complete 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 in the Marcellus Shale formation on the lease acreage that will have a perforated segment that will be within 500 feet of any perforated interval of any PUD or Producing Well.

        In the conveyance documents for the PUD Royalty Interest, ECA expressly excepted and reserved all right, title and interest in and to any well and appurtenant production facilities not expressly conveyed to the Trust. The PDP Royalty Interest is included within the AMI and those properties will remain subject to the terms and conditions of the PDP Royalty Interest conveyance documents.

        The PUD Royalty Interest conveyances further provide that the Trust's PUD Royalty Interest will be applicable to any additional acreage leased or acquired by any other means by ECA within the AMI until the drilling obligation of ECA to the Trust is met. Subject to the terms of the PUD Royalty Interest, ECA, in its sole discretion, may add such additional acreage to the Trust, and may exchange acreage for other acreage in the AMI, provided the aggregate acreage attributable to additional leases and the exchange leases shall not exceed five percent of the acreage currently subject to the PUD Royalty Interest. No assurance can be given, however, that any development well will produce in commercial quantities or that the characteristics of any development well will match the characteristics of ECA's existing wells or ECA's historical drilling success rate. ECA operates all of the Producing Wells and has agreed to operate not less than 90% of the PUD Wells during the subordination period.

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.

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        Proved reserves of the royalty interests.    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 revenues 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 Underlying Properties 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 Appendix A to this report.

        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 report. The Trust has not filed reserve estimates covering the Royalties with any other federal authority or agency.

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

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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, the independent petroleum engineering consultant, estimated, 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, all of the proved reserve information in this report. 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. These same industry wide applied techniques are used in determining our estimated reserve quantities. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Society of Petroleum Engineers' Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information. ECA's internal control over its reserve reporting process is designed to result in accurate and reliable estimates in compliance with applicable regulations and guidance. Internal reserve preparation is performed 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 during the reserve estimation process to review properties, assumptions, and any new data available. Additionally, ECA's senior management reviewed and approved all Ryder Scott reserve reports contained herein.

        ECA's reserves are first estimated by a Staff Reservoir Engineer before being reviewed by the Senior Reservoir Engineer. The 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. During that time, he has focused on reserves estimates and project economics.

        ECA's Vice President of Eastern Operations is the primary technical person responsible for overseeing the reserve 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

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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. He has over six years of experience in reserve evaluation.

        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 five PUD wells, which have since been classified as proved developed. Finally, ECA drilled three 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 royalty interests. 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.

Title to Properties

        The Underlying 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.

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        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 and the royalty interests 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 a preliminary title review of the PUD Wells. Prior to drilling a 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. The conveyance related to the PUD Royalty Interest obligates 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.

        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.

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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 gas properties to which the Underlying Properties 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 initially burdened 50% of all of the interests of ECA in the Marcellus Shale formation in the AMI. ECA's interests in the gas properties to which the PUD Wells relate consist of an average working interest of 100%. The conveyance related to the PUD Royalty Interest, however, provides 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 conveyance related to the PUD 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.

        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,

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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 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 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 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 will be 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 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 Producing Wells, including any costs to plug and abandon a Producing Well.

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        PUD Royalty Interest.    The conveyance creating the PUD Royalty Interest entitles 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, which 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 charges 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 Services Fee to the extent necessary to recover certain capital expenditures in ECA's Greene County Gathering System. Additionally, the Trust will be 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 report 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.

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        "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.

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.

        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 report, 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.

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        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.

        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.

Item 3.    Legal Proceedings.

        None.

Item 4.    (Removed and Reserved.)

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PART II

Item 5.    Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

        The Trust units commenced trading on the New York Stock Exchange on July 1, 2010 under the symbol "ECT." Prior to July 1, 2010, there was no established public trading market for the Trust units. The high and low sales prices per unit for each quarter in 2010 were as follows:

        At December 31, 2010, the 17,605,000 units outstanding were held by 32 unitholders of record.

Distributions

        Each quarter, the Trustee determines the amount of funds available for distribution to the Trust unitholders, as described elsewhere in this report. Quarterly cash distributions during the term of the Trust are made by the Trustee generally no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 45th day following the end of each quarter (or the next succeeding business day). The table below presents the net cash proceeds for each quarter of 2010, the Trust expenses, and the resulting distributable income per Trust unit (dollars in thousands, except distributable income per unit).

        Subsequent to year end, on February 28, 2011, a distribution of $0.500 per Trust unit was paid to Trust unitholders owning Trust units as of February 14, 2011.

Equity Compensation Plans

        The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.

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.

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Purchases of Equity Securities

        Except as described in the Prospectus, there were no purchases of Trust units by the Trust or any affiliated purchaser during the fourth quarter of 2010.

Item 6.    Selected Financial Data.

        The following is a summary of royalty income and distributable income per unit by quarter in 2010 (all amounts in thousands except Distributable income per unit):

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Item 7.    Trustee's Discussion and Analysis of Financial Condition and Results of Operation.

        This document contains forward-looking statements, which describe current expectations or forecasts of future events. Please refer to "Forward-Looking Statements" which follows the Table of Contents of this Form 10-K for an explanation of these types of statements.

Overview

        The Trust is a statutory trust created under the Delaware Statutory Trust Act. The Bank of New York Mellon Trust Company, N.A. serves as Trustee. The Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Royalties, to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalties after payment of Trust expenses, and to perform certain administrative functions in respect of the Royalties and the Trust units. The Trust derives all or substantially all of its income and cash flows from the Royalties, which in turn are subject to the hedge contracts described in Part I, Item 3. The Trust is treated as a partnership for federal income tax purposes.

        As of December 31, 2010 the Trust owned royalty interests in the 14 Producing Wells, royalty interests in six PUD Wells that were online and producing two PUD Wells that were completed but awaiting initial production, and royalty interests in the remaining horizontal natural gas development wells to be drilled to the Marcellus Shale formation within the AMI, in which ECA presently holds approximately 9,300 acres, of which it owns substantially all of the working interests, in Greene County, Pennsylvania. The AMI consists of the Marcellus Shale formation in approximately 121 square miles in Greene County, Pennsylvania. ECA is obligated to drill the remaining 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 on lease acreage included within the AMI for its own account.

        The Royalties were conveyed from ECA's working interest in the Producing Wells and the PUD Wells limited to the Marcellus Shale formation. 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 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. Approximately 50% of the estimated natural gas production attributable to the Royalties 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.

        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. As of December 31, 2010, ECA had drilled 16.29 of the PUD Wells, calculated as provided in the Development Agreement. The Trust will not be 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 is 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 the hedge 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

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gathered until ECA has fulfilled its drilling obligation; 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 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 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 is 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 are 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 from any well or wells exceeding 2,500 feet. 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.

        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 first quarterly distribution was made on August 31, 2010 to record unitholders as of August 16, 2010.

        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 transferred to the Trust; and



•

administrative expenses of the Trust and expenses incurred as a result of being a publicly traded entity, and any changes in amounts reserved for such expenses.

        The amount of the quarterly distributions will fluctuate from quarter to quarter, depending on the proceeds received by the Trust, among other factors. 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. While the subordinated units will be 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 thresholds set forth below, if there is not sufficient cash to fund such a distribution on all Trust units,

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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. 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 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. 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 subordination and incentive thresholds for each calendar quarter through the first quarter of 2015. The effective date of the Trust is April 1, 2010, meaning it has

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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 July 7, 2010.

Results of Trust Operations

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 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 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.

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        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 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 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 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 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.

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        Because the Trust reached the incentive distribution threshold amount to be paid on all trust units for the quarter 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 fourteen PUD Wells as of February 23, 2011 and twelve of these wells are undergoing or awaiting completion operations while two were brought online in early January 2011. As of February 23, 2011, ECA has drilled a total of twenty actual PUD Wells. However, the average horizontal lateral distance for these twenty wells (as measured from the midpoint of the curve to the end of the lateral) was 3,881 feet and represents a total of 25.43 net PUD Wells drilled, calculated as described in the Prospectus. These 25.43 net PUD Wells drilled count toward the 52 equivalent PUD Wells ECA has committed to drill.

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 report, 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.

Off-Balance Sheet Arrangements

        The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations other than the commodity hedge contracts disclosed in the section "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Annual Report on Form 10-K.

Contractual Obligations

        Pursuant to the Trust Agreement, the Trust is obligated to pay the Trustee an administrative fee of $150,000 per year, and the Trust is obligated to pay the Delaware Trustee a fee of $2,400 per year.

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Additionally, 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, is $60,000 per year.

New Accounting Pronouncements

        None.

Critical Accounting Policies and Estimates

Significant Accounting Policies

        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 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 will only be charged to the Trust 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 unitholders' 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.

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 write down 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 write down 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

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Underlying Properties. Any such write down would not reduce Distributable Income, although it would reduce Trust Corpus.

        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.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Hedge Contracts

        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 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 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 commencing as of April 1, 2010 through June 30, 2012. The price of the floor price hedging contracts is $5.00 per MMBtu.

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        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.

        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.

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Item 8.    Financial Statements and Supplementary Data.

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.

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

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

See notes to the financial statements.

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ECA Marcellus Trust I

Statement of Trust Corpus

As of December 31, 2010

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

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NOTES TO FINANCIAL STATEMENTS (Continued)

FOR THE PERIODS ENDED DECEMBER 31, 2010

NOTE 1. Organization of the Trust (Continued)

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 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

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FOR THE PERIODS ENDED DECEMBER 31, 2010

NOTE 1. Organization of the Trust (Continued)

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.

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

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NOTES TO FINANCIAL STATEMENTS (Continued)

FOR THE PERIODS ENDED DECEMBER 31, 2010

NOTE 3. Significant Accounting Policies (Continued)

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 Properties. Any such writedown would not reduce Distributable Income, although it would

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NOTES TO FINANCIAL STATEMENTS (Continued)

FOR THE PERIODS ENDED DECEMBER 31, 2010

NOTE 3. Significant Accounting Policies (Continued)

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.

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FOR THE PERIODS ENDED DECEMBER 31, 2010

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 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.

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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:

        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):

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        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):