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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the quarterly period ended September 30, 2010

OR

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from                           to                          

Commission File Number: 001-34800

ECA MARCELLUS TRUST I

(Exact name of registrant as specified in its charter)

1-800-852-1422
(Registrant’s telephone number, including area code)

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 o No x

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 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 Exchange Act). Yes o No x

As of November 12, 2010, 13,203,750 Common Units and 4,401,250 Subordinated Units of Beneficial Interest in ECA Marcellus Trust I were outstanding.

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GLOSSARY OF CERTAIN TERMS

The following are definitions of certain significant terms used in this report.  Other terms are defined in the text of this report.

“Completion” (or its derivatives) means that the well has been perforated, stimulated, tested and permanent equipment for the production of natural gas has been installed.

“FASB ASC” means the Financial Accounting Standards Board Accounting Standards Codification.

“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.

“Incentive Threshold” means, for any particular quarter (through the first quarter of 2015), the amount shown in the column titled “Incentive Threshold” in the section titled “Overview” in Management’s Discussion and Analysis in this report.  In exchange for agreeing to subordinate the 4,401,250  Trust units it owns, 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.

“MMBtu” means one million British Thermal Units.

“Mcf” means one thousand standard cubic feet of natural gas.

“MMcf” means one million standard cubic feet of natural gas.

“Producing Wells” means the 14 natural gas wells located in Greene County, Pennsylvania and described as the “Producing Wells” in the Prospectus.

“Prospectus” means the final prospectus relating to the initial public offering of the Trust units as filed with the SEC pursuant to rule 424(b) on June 30, 2010.

“PUD Wells” means the horizontal natural gas development wells to be drilled by ECA to the Marcellus Shale formation within the “Area of Mutual Interest,” or “AMI”, described in the Prospectus and located in Greene County, Pennsylvania.  The number of PUD Wells drilled is to be computed as described in the Prospectus, and the actual number of PUD Wells drilled may be more or less than 52.

“Reserves” means estimated remaining quantities of natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“SEC” means the United States Securities and Exchange Commission.

“Subject Gas” means Gas from the Marcellus Shale formation from any Producing Well or PUD Well.

“Subject Interest” means ECA’s undivided interests in the AMI, as lessee under Gas leases, as an owner of the Subject Gas (or the right to extract such Gas), or otherwise, by virtue of which undivided interests ECA has the right to conduct exploration and Gas production operations on the AMI.

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“Subordination Threshold” means, for any particular quarter (through the first quarter of 2015), the amount shown in the column titled “Subordination Threshold” in the section titled “Overview” in Management’s Discussion and Analysis in this report.  In order to provide support for cash distributions on the common units, ECA has agreed to subordinate the 4,401,250  trust units it owns, which constitute 25% of the outstanding trust units. While the subordinated units are entitled to receive pro rata distributions from the Trust if and to the extent there is sufficient cash to provide a cash distribution on the common units which is at least equal to the applicable quarterly subordination threshold, if there is not sufficient cash to fund such a distribution on all trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units.

“Trust Gas” means that percentage of Gas to which the Trust is entitled, calculated in accordance with the provisions of the conveyances of the royalty interests.

“Working Interest” means the interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to share in production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development and operations and all risks in connection therewith.

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PART I-FINANCIAL INFORMATION

Item 1. Financial Statements.

ECA Marcellus Trust I

Statement of Assets, Liabilities, and Trust Corpus

As of September 30, 2010

See notes to the unaudited financial statements.

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ECA Marcellus Trust I

Statement of Distributable Income

Unaudited

See notes to the unaudited financial statements.

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ECA Marcellus Trust I

Statement of Trust Corpus

As of September 30, 2010

See notes to the unaudited financial statements.

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ECA MARCELLUS TRUST I

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

NOTE 1.  Organization of the Trust

ECA Marcellus Trust I is a Delaware statutory trust formed in March 2010 by Energy Corporation of America (“ECA”) to own royalty interests in fourteen producing horizontal natural gas wells producing from the Marcellus Shale formation, all of which are online and are located in Greene County, Pennsylvania (the “Producing Wells”) and royalty interests in 52 horizontal natural gas development wells to be drilled to the Marcellus Shale formation (the “PUD Wells”) within the “Area of Mutual Interest,” or “AMI”, comprised of approximately 9,300 acres held by ECA, of which it owns substantially all of the working interests, in Greene County, Pennsylvania. The effective date of the Trust was April 1, 2010; consequently, the Trust received the proceeds of production attributable to the PDP Royalty Interest from that date even though the PDP Royalty Interest was not conveyed to the Trust until the closing of the initial public offering on July 7, 2010.  The total number of units the Trust is authorized to issue is 17,605,000 units, of which 13,203,750 are common units and 4,401,250 are subordinated units. The royalty interests were conveyed from ECA’s working interest in the Producing Wells and the PUD Wells limited to the Marcellus Shale formation (the “Underlying Properties”). The royalty interest in the Producing Wells (the “PDP Royalty Interest”) entitles the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells. The royalty interest in the PUD Wells (the “PUD Royalty Interest” and collectively with the PDP Royalty Interest, the “Royalty Interests”) entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells. Approximately 50% of the estimated natural gas production attributable to the Trust’s royalty interests has been hedged with a combination of floors and swaps through March 31, 2014. The floor price contracts were transferred to the Trust by ECA, while ECA entered into a back-to-back swap agreement with the Trust to provide the Trust with the benefit of swap contracts entered into between ECA and third parties. ECA will be entitled to recoup the costs of establishing the floor price contracts only if and to the extent cash available for distribution by the Trust exceeds certain levels.

ECA is obligated to drill all of the PUD Wells by March 31, 2013; however, in the event of delays, ECA will have until March 31, 2014 to fulfill its drilling obligation. ECA has granted to the Trust a lien (the “Drilling Support Lien”) on ECA’s interest in the Marcellus Shale formation in the AMI (except the Producing Wells and any other wells which are already producing and not subject to the Royalty Interests) in order to secure the estimated amount of the drilling costs for the Trust’s interests in the PUD Wells. The amount obtained by the Trust pursuant to the Drilling Support Lien may not exceed $91 million. As ECA fulfills its drilling obligation over time, the total dollar amount that may be recovered will be proportionately reduced and the drilled PUD Wells will be released from the lien.

The Trust is not responsible for any costs related to the drilling of development wells or any other development or operating costs. The Trust’s cash receipts in respect of the royalties will be determined after deducting post-production costs and any applicable taxes associated with the PDP and PUD Royalty Interests, and the Trust’s cash available for distribution will include cash receipts from its hedging contracts and will be reduced by Trust administrative expenses and expenses incurred as a result of being a publicly traded entity. Post-production costs will generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production costs on its Greene County Gathering System will be limited to $0.52 per MMBtu gathered until ECA has fulfilled its drilling obligation (the “Post-Production Services Fee”); thereafter, ECA may increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System.

Generally, the percentage of production proceeds to be received by the Trust with respect to a well will equal the product of (i) the percentage of proceeds to which the Trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) ECA’s net revenue interest in the well. ECA on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the Trust will be entitled to

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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 is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Trust units in any quarter exceeds 150% of the subordination threshold for such quarter.  ECA’s right to receive the incentive distributions will terminate upon the expiration of the subordination period.

ECA incurred costs of approximately $5.0 million for floor price contracts that were transferred to the Trust. ECA is entitled to reimbursement for these expenditures plus interest accrued at 10% per annum only if and to the extent distributions to Trust unitholders would otherwise exceed the incentive threshold. This reimbursement will be deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the Trust unitholders.

The subordinated units will automatically convert into common units on a one-for-one basis and ECA’s right to receive incentive distributions and to recoup the reimbursement amount will terminate, at the end of the fourth full calendar quarter following ECA’s satisfaction of its drilling obligation to the Trust. Accordingly, ECA bears the risk that it will not be partially or fully reimbursed for the floor price contracts transferred to the Trust. ECA currently expects that it will complete its drilling obligation on or before March 31, 2013 and that, accordingly, the subordinated units will convert into common units on or before March 31, 2014. In the event of delays, it will have until March 31, 2014 under its contractual obligation to drill all the PUD Wells, in which event the subordinated units would convert into common units on or before March 31, 2015. The period during which the subordinated units are outstanding is referred to as the “subordination period.”

The business and affairs of the Trust are managed by The Bank of New York Mellon Trust Company, N.A. as Trustee. Although ECA operates all of the Producing Wells and substantially all of the PUD Wells, ECA has no ability to manage or influence the management of the Trust.

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NOTE 2.  Basis of Presentation

The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Without limiting the foregoing statement, the information furnished is based upon certain estimates of the revenues attributable to the Trust from natural gas production for the three month and inception to date periods ended September 30, 2010 and is therefore subject to adjustment in future periods to reflect actual production for the periods presented.

The information furnished reflects all adjustments which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim period presented. The accompanying unaudited interim financial statements should be read in conjunction with the audited financial statements and notes thereto included in the final prospectus filed with the SEC by ECA pursuant to Rule 424(b) under the Securities Act of 1933 on July 1, 2010 (the “Prospectus”).

NOTE 3.  Significant Accounting Policies

The accompanying unaudited financial information has been prepared by the Trustee in accordance with the instructions to Form 10-Q.  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 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 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.

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.

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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 reduce Trust Corpus.  No impairment in the Underlying Properties was recognized during the three-month period ended September 30, 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 September 30, 2010, the amount of unrecorded accrued interest payable to ECA was $189,208.

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 period ended September 30, 2010 totaled $1,629,368 and $3,443,911, 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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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 royalty interests. 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.

NOTE 7.  Subsequent Events

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 October 1, 2010, ECA had received a partial release of the Drilling Support Lien in the amount of approximately $4.1 million.

As of November 7, 2010, two additional PUD wells had been brought online by ECA that were producing 1,560 Mcf per day net to the Trust’s interest as of November 8, 2010.   Also, one Producing Well that had previously been shut-in began curtailed production.  On November 8, 2010 this well was producing 2,506 Mcf per day, net to the Trust’s interest.

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Item 2.                                   Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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.  References to “EMCO” in this document refer to Eastern Marketing Corporation, a wholly-owned subsidiary of ECA.

The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto, as well as the Discussion and Analysis of Historical Results from the Producing Wells contained in the Prospectus. The Trust’s Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are or will be available on the SEC’s website at www.sec.gov.

Note Regarding Forward-Looking Statements

This Form 10-Q 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 “Management’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 and conditions in the capital markets;

·         competition from others in the energy industry; and

·         uncertainty of estimates of natural gas reserves and production.

·         other risks described under the caption “Risk Factors” in this Report on Form 10-Q.

All written and oral forward-looking statements attributable to ECA or the Trust or persons acting on behalf of ECA or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.

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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 (described below), to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalties 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.

The Trust owns royalty interests in fourteen  producing horizontal natural gas wells producing from the Marcellus Shale formation and 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”, 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. 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 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”) 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 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 September 30, 2010, ECA had drilled 8.26 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 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 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 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

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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 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 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 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, 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

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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 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 September 30, 2010

The Trust’s distributable income was $7,419,059 for the three months ended September 30, 2010.  This amount exceeded the projected cash available for distribution determined in establishing the target distributions described in the Prospectus by approximately $69,000.

Total revenues for the quarter of $7.9 million were $161,000 greater than the projected amount of $7.8 million.  This increase in revenues was attributable to production volumes being greater than projected amounts by 220 MMcf.  This increase in production for the quarter was the result of the average per well production being higher than projected.  Fifteen wells were online and producing during the quarter, with one additional well temporarily shut-in awaiting completion of a pipeline expansion at September 30, 2010.  The shut in well was brought back online on October 2, 2010.

The increased production was partially offset by the average price received for the quarter, net of the post production services fee, of $4.89 per Mcf being $0.66 per Mcf lower than the projected price of $5.55 per Mcf.   This lower realized price per Mcf was primarily the result of a 16% increase in production volumes, which reduced the percentage of production covered by the higher swap price of $6.75 per MMbtu, resulting in a lower overall

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average price per Mcf for the three months.  Hedge proceeds received for the three months were $316,000 higher than the projected amount due to lower NYMEX prices.

General and administrative expenses paid by the Trust were $659,000 for the three months ended September 30, 2010.  This amount was $252,000 greater than the projected expenses for the quarter primarily due to the timing of payment of invoices received and the availability of the cash reserve previously established.  During the three months ended September 30, 2010 the Trustee received a quarterly fee of $37,500 and ECA received a quarterly Administrative Services Fee of $15,000.  The Trustee released $160,000 of the cash reserve previously established due to reduction of projected expenses to be paid over the next quarter which increased the Trust’s distributable income for the period.

The 14 Producing Wells conveyed to the Trust and two PUD Wells drilled were online and producing during the three months ended September 30, 2010.  Of the 14 Producing Wells, six wells were awaiting completion at June 30, 2010.  Three of these wells were brought online in early July and three wells were brought online in late August.  These six wells have an average Trust daily production rate of 9,218 Mcf per day as of November 8, 2010.   The average Trust daily production for the two PUD wells, which were brought online in mid-September, was 2,206 Mcf per day as of November 8, 2010.  The average initial per well production for the final three Producing Wells and the first two PUD wells for the first thirty days of production was 3,122 Mcf per day which is 38% above the rate forecasted by the Ryder Scott Reserve Report described in the Prospectus for the same time period.

ECA has drilled an additional seven PUD Wells as of November 4, 2010 and these wells are undergoing or awaiting completion operations.  To date, ECA has drilled a total of nine actual PUD Wells.  However, the average horizontal lateral distance for these nine wells (as measured from the midpoint of the curve to the end of the lateral) was 4,071 feet and represents a total of 11.06 net PUD Wells drilled, calculated as described in the Prospectus.  These 11.06 net PUD Wells drilled count toward the 52 equivalent PUD Wells ECA has committed to drill.

From Inception to Date to the Period Ended September 30, 2010

The Trust’s distributable income was $12,207,620 from inception to date through September 30, 2010.  This amount exceeded the projected cash available for distribution determined in establishing the target distributions described in the Prospectus by approximately $870,000.

Total revenues from inception through September 30, 2010 were $13.5 million and were approximately $1.3 million greater than the projected amount of $12.2 million.  This increase in revenues was attributable to production volumes being greater than projected amounts by 513 MMcf.  This increase in production for the period was the result of the average per well production being higher than projected.  Fifteen wells were online and producing during the period with one additional well temporarily shut-in awaiting completion of a pipeline expansion at September 30, 2010.  The shut in well was brought back online on October 2, 2010.

The increased production was partially offset by the average price received for the periods, net of the post production services fee, of $5.21 per Mcf being $0.65 per Mcf lower than the projected price of $5.86 per Mcf.  This lower realized price per Mcf was primarily the result of the 25% increase in production volumes, which reduced the percentage of production covered by the higher swap price of $6.75 per MMbtu, resulting in a lower overall average price per Mcf.  Hedge proceeds received for the period were $359,000 higher than the projected amount due to lower than projected NYMEX prices.

General and administrative expenses paid by the Trust were $659,000 for the period ended September 30, 2010.  This amount was $155,000 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 June 30, 2010.  Neither the Trustee nor ECA waived its fees for the quarter ended September 30, 2010 and neither intends to do so in the future.  From inception thru September 30, 2010, the Trustee has established a cash reserve of $500,000 for use in paying the current and future liabilities of the Trust as they become due.  This cash reserve reduced the Trust’s income for the period.

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

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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.

The 14 Producing Wells conveyed to the Trust and two PUD Wells drilled were online and producing during the three months ended September 30, 2010.  Of the 14 Producing Wells, six wells were awaiting completion at June 30, 2010.  Three of these wells were brought online in early July and three wells were brought online in late August.  These six wells have an average Trust daily production rate of 9,218 Mcf per day as of November 8, 2010.   The average Trust daily production for the two PUD wells, which were brought online in mid-September, was 2,206 Mcf per day as of November 8, 2010.  The average initial per well production for the final three Producing Wells and the first two PUD wells for the first thirty days of production was 3,122 Mcf per day which is 38% above the rate forecasted by the Ryder Scott Reserve Report described in the Prospectus for the same time period.

ECA has drilled an additional seven PUD Wells as of November 4, 2010 and these wells are undergoing or awaiting completion operations.  To date, ECA has drilled a total of nine actual PUD Wells.  However, the average horizontal lateral distance for these nine wells (as measured from the midpoint of the curve to the end of the lateral) was 4,071 feet and represents a total of 11.06 net PUD Wells drilled, calculated as described in the Prospectus.  These 11.06 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.

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

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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.

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 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 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 3.  Quantitative and Qualitative Disclosures About Market Risk.

Hedge Contracts

The primary asset of and source of income to the Trust is the Royalties, which generally entitle the Trust to receive varying portions of the net proceeds from gas production from the underlying properties. Consequently, the

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Trust is exposed to market risk from fluctuations in gas prices. Through March 31, 2014, however, the Royalties are subject to the Hedge Contracts, 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 any floor price hedging contract 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.

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.

Item 4.  Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Act is accumulated and communicated by ECA to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

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Due to the contractual arrangements of (i) the Trust Agreement, (ii) the Administrative Services Agreement and (iii) the conveyances of the Royalties, the Trustee relies on (A) information provided by ECA, including results of operations, the status of drilling the PUD Wells, the costs and revenues attributable to the Trust’s interests under the Conveyances, historical and other operating data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and all other information relating to the status and results of operations of the properties in which the Trust has an interest, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.  See Item 1A “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operation”, for a description of certain risks relating to these arrangements and reliance on information.

Changes in Internal Control over Financial Reporting. During the quarter ended September 30, 2010, there has been no change in the Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee’s internal control over financial reporting relating to the Trust. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of ECA.

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PART II-OTHER INFORMATION

Item 1A. Risk Factors.

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;

·                  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

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·                  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;

·                  governmental regulations and taxation; and

·                  energy conservation and environmental measures.

From 2006 through 2009 the highest monthly NYMEX settled price was $13.11 per MMBtu and the lowest was $2.84 per MMBtu. In addition, the market price of natural gas is generally higher in the winter months than during other months of the year due to increased demand for natural gas for heating purposes during the winter season.

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

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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. Also, Pennsylvania oil and gas production data is kept confidential for five years, and the first Marcellus Shale production in the state was in 2005. Furthermore, the use of horizontal drilling methods on the Underlying Properties is a recent development in the Marcellus Shale, with ECA commencing the drilling of its first horizontal well in the Marcellus Shale in 2007. The lack of operational history for horizontal wells in the Marcellus Shale formation may also contribute to the inaccuracy of estimates of proved reserves. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates, including variances attributable to a lack of production history within the Marcellus Shale formation, would have a material adverse effect on the financial condition, results of operations and cash flows of the Trust and would reduce cash distributions to Trust unitholders.

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 Senate and House recently introduced legislation that would have imposed a severance tax of 5% of the value of natural gas at the wellhead plus $0.047 per thousand feet of natural gas severed. Although it does not appear such legislation will be enacted into law this year, 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 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

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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 may, in the future, seek to obtain 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.

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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 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 royalty interests, 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 royalty interests 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 royalty interests 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 Trust’s royalty interest. 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.

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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 royalty interests 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 reserve report, the gas production from proved producing reserves attributable to the PDP Royalty Interest is projected to decline at an average rate of approximately 8.5% per year over the life of the Trust. As a PUD Well is drilled and placed on production, the production rate is expected to decline approximately 37.3% during the first year of production, approximately 14.7% during the next three to five years of production and approximately 8.0% per year for the remainder of the economically productive life of the well. These production characteristics are generally consistent with other development wells in the AMI. The anticipated rate of decline is an estimate and actual decline rates may vary from those estimated.

Future maintenance may affect the quantity of proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these projects will depend on, among other factors, the market prices of natural gas. With the exception of ECA’s commitment to drill the PUD Wells, ECA has 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 will provide that the Trust’s business activities will be limited to owning the royalty interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the royalty interests. As a result, the Trust will not be 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 royalty interests and the Trust will bear certain costs and expenses that will 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 will utilize ECA’s Greene County Gathering System. The Trust will pay 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 will be charged for the cost of fuel used in the compression process or equivalent electricity charges when electric compressors are used.

·                  There currently are no third party post-production costs; however, 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.

·                  Taxes allocated to or imposed on the Trust will 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

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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 will bear 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 will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees and registrar and transfer agent fees.

·                  ECA will be 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 “Description of the Trust agreement — Fees and expenses — Fees to ECA” in the Prospectus.

·                  ECA has incurred costs of approximately $5 million in establishing the floor price contracts to be transferred to the Trust. ECA will be entitled to reimbursement for these expenditures 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.

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 Trust’s royalty interests, 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 Trust’s royalty interests will be 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 Trust’s royalty interests that is hedged. The Trust will not have any ability to terminate the swaps before the expiration date.

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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 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 the Prospectus under the caption “Target distributions and subordination and incentive thresholds,” are based on ECA’s calculations, and ECA has not received an opinion or report on such calculations from any independent accountants. Such calculations 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

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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 development 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 royalty interests 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 royalty interests if unitholders approve the sale or vote to dissolve the Trust. The Trustee must also sell the royalty interests if the gross proceeds to the Trust attributable to the Royalty Interests 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 royalty interests 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.”

ECA and the Private Investors 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. In addition, the Private Investors hold 1,104,567 common 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 and the Private Investors have agreed not to sell any Trust units for a period of 180 days after the date of the Prospectus without the consent of Raymond James & Associates, Inc. and Citigroup Global Markets Inc., acting as representatives of the several underwriters. See “Underwriting” in the Prospectus. After such period, ECA and the Private Investors 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 and the Private Investors 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.

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·                  ECA may sell some or all of the Underlying Properties, subject to its obligation not to sell any of the underlying PUD properties prior to satisfying its obligation to drill the PUD Wells. Such sale may not be in the best interests of the Trust unitholders. Any purchaser may lack ECA’s experience in the Marcellus Shale or its credit worthiness.

·                  ECA may, without the consent of the Trust unitholders, require the Trust to release royalty interests with an aggregate value to the Trust of up to $5.0 million during any 12-month period. These releases will be made only in connection with the sale by ECA of the Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such royalty interests. See “The underlying properties — Sale and abandonment of underlying properties.”

·                  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 royalty interests 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.

·                  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 will be 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 royalty interests, 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

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assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

ECA is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose ECA to significant liabilities.

ECA’s natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these laws and regulations, ECA must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. ECA may incur substantial costs in order to maintain compliance with these existing laws and regulations. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of natural gas and fluids as a result of drilling activities in the Marcellus Shale, there has been a variety of regulatory initiatives at the federal and state level to restrict oil and gas drilling operations in certain locations. Any increased regulation or suspension of oil and gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on ECA’s business, financial condition and results of operations. ECA must also comply with laws and regulations prohibiting fraud and market manipulations in energy 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, additional regulation of and restrictions on hydraulic fracturing of wells, 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, 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

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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 Trust’s royalty interest and its ultimate cash available for distribution will be highly dependent on ECA’s performance. ECA will not be a reporting company following this offering and will not file periodic reports with the SEC. Therefore, as a Trust unitholder, you will 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 royalty interests 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 royalty interests 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 royalty interests 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 royalty interests 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 royalty interests 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 royalty interests 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 royalty interests. During the pendency of ECA’s bankruptcy proceedings, the Trust’s ability to foreclose on the Drilling Support Lien or the Royalty Interest Lien, and the ability to collect cash payments from customers being held in ECA’s accounts that are attributable to production from the Trust properties, may be stayed by the bankruptcy court. Delay in realizing on the collateral for the Drilling Support Lien and the Royalty Interest Lien is possible, and it cannot be guaranteed that a bankruptcy court would permit such foreclosure. It is possible that the bankruptcy would also delay the execution of a new agreement with another driller or operator. If the Trust enters into a new agreement with a drilling or operating partner, the new partner might not achieve the same levels of production or sell natural gas at the same prices as ECA was able to achieve.

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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. In addition, the risk of accidental spills or releases could expose ECA to significant liabilities that could have a material adverse effect on its financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require ECA to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition. ECA may not be able to recover some or any of these costs from insurance. As a result of the increased cost of compliance, ECA may decide to discontinue drilling. Additionally, permitting delays may inhibit ECA’s ability to drill the PUD Wells on schedule.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas that ECA produces while the physical effects of climate change could disrupt ECA’s production and cause ECA to incur significant costs in preparing for or responding to those effects.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment. These findings allow the agency to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed regulations that would require a reduction in emissions of GHGs from motor vehicles and adopted regulations that could trigger permit review for GHG emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, beginning in 2011 for emissions occurring in 2010. Only very recently, on March 23, 2010, the EPA announced a proposed rulemaking that would

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expand its final rule on reporting of GHG emissions to include owners and operators of onshore oil and natural gas production. If the proposed rule is finalized in its current form, monitoring of those newly covered sources would commence on January 1, 2011. Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009” (“ACESA”), which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of GHGs. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of GHGs into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and the Obama Administration has indicated its support for legislation to reduce GHG emissions through an emission allowance system. 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.

The U.S. Congress is considering legislation that would amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act. 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. Sponsors of the legislation have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the legislation could result in additional regulatory burdens involving permitting, construction standards for wells, monitoring, recordkeeping and closure of wells. The legislation also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, 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. 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 pending congressional legislation or 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 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.

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Tax Risks Related to the Trust’s Common Units

The Trust’s tax treatment depends on its status as a partnership for federal income tax purposes. If the IRS were to treat the Trust as a corporation for federal income tax purposes, then its cash available for distribution to you would be substantially reduced.

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. The Trust has not requested, and does not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting it.

It is possible in certain circumstances for a publicly traded Trust otherwise treated as a partnership, such as the Trust, to be treated as a corporation for federal income tax purposes. 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.

If the Trust was treated as a corporation for federal income tax purposes, it would pay 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 the Trust unitholders, 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 federal income tax purposes, the minimum quarterly distribution amount and 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. 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 an investment in Trust units could be affected by recent and potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The recently enacted Health Care and Education Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects an individual having adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to an additional “medicare tax” equal generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include interest income and royalty income derived from investments such as the Trust units as well as any net gain from the disposition of Trust units. In addition, absent new legislation extending the current rates, beginning January 1, 2011, 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.

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Current law may change so as to cause the Trust to be treated as a corporation for federal income tax purposes or otherwise subject the Trust to entity-level taxation. Specifically, the present 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, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to the Trust as currently proposed, it could be amended prior to enactment in a manner that does apply to the Trust.

The Trust will adopt positions that may not conform to all aspects of existing Treasury Regulations. If the IRS contests the federal income tax positions the Trust takes, the value of the Trust units may be adversely affected, the cost of any IRS contest will reduce the Trust’s cash available for distribution to you and income, gain, loss and deduction may be reallocated among Trust unitholders.

The Trust will treat each purchaser of common units as having the same economic attributes without regard to the actual common units purchased. Moreover, the Trust will generally prorate its 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 Trust unit is transferred. Although simplifying conventions are contemplated by the Internal Revenue Code, and most publicly traded partnerships use similar simplifying conventions, the use of these methods may not be permitted under existing Treasury Regulations. 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. Please read “Federal Income Tax Considerations — Disposition of Trust Units — Recognition of Gain or Loss” in the Prospectus for a further discussion of the foregoing.

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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, distributions to non-U.S. persons will 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. If you are a tax exempt entity or a non-U.S. person, you should consult a tax advisor before investing in the Trust units.

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. See “Federal income tax considerations — Tax consequences of Trust unit ownership — Section 754 election” in the Prospectus.

The Trust will prorate its 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 Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.

The Trust will generally prorate its 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 Trust unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, the Trust’s counsel is unable to opine as to the validity of this method. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method the Trust will adopt. If the IRS were to challenge the Trust’s proration method, the Trust may be required to change its allocation of items of income, gain, loss and deduction among the Trust unitholders. See “Federal Income Tax Considerations — Disposition of Trust units — Allocations between transferors and transferees” in the Prospectus.

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, he may no longer be treated for 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.

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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.

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 2011 (the “2011 Budget”) is the elimination of certain key U.S. federal income tax preferences relating to natural gas exploration and production. The 2011 Budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources effective in 2011. Specifically, the 2011 Budget proposes to repeal the deduction for percentage depletion with respect to oil and natural gas wells, including interests such as the Perpetual Royalty Interests, in which case only cost depletion would be available.

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Item 6. Exhibits.

The exhibits listed in the accompanying index to exhibits are filed as part of the Quarterly Report on Form 10-Q.

*Exhibit previously filed with the SEC and incorporated herein by reference to the exhibit of like designation filed with the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800).

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: November 12, 2010

The registrant, ECA Marcellus Trust I, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust agreement under which it serves.

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EXHIBIT INDEX

*Exhibit previously filed with the SEC and incorporated herein by reference to the exhibit of like designation filed with the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800).

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