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 June 30, 2013

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)

Delaware		27-6522024
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

The Bank of New York Mellon
Trust Company, N.A., Trustee
Global Corporate Trust
919 Congress Avenue
Austin, Texas		78701
(Address of principal executive offices)		(Zip Code)

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 x No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o	Accelerated filer x	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller
		reporting company)

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 August 9, 2013, 17,605,000 Common Units of Beneficial Interest in ECA Marcellus Trust I were outstanding.

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PART I-FINANCIAL INFORMATION

Item 1. Financial Statements.

ECA Marcellus Trust I

Statements of Assets, Liabilities, and Trust Corpus

(Unaudited)

	As of			As of
	June 30, 2013			December 31, 2012
ASSETS:
Cash	$	1,023,951		$	1,955,202
Royalty income receivable	7,407,502			7,081,475
Floor price contracts	1,565,520			2,786,520

Royalty interest in gas properties	352,100,000			352,100,000
Accumulated amortization	(104,150,318		)	(87,947,444		)
Net royalty interest in gas properties	247,949,682			264,152,556

Total Assets	$	257,946,655		$	275,975,753

LIABILITIES AND TRUST CORPUS:
Liabilities:
Distributions payable to unitholders	8,396,500			9,009,391

Trust corpus; 17,605,000 common units authorized, issued and outstanding	249,550,155			266,966,362

Total Liabilities and Trust Corpus	$	257,946,655		$	275,975,753

See notes to the unaudited financial statements.

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ECA Marcellus Trust I

Statements of Distributable Income

(Unaudited)

	Six Months Ended						Three Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Royalty income	$	13,328,509		$	9,774,726		$	7,407,502		$	4,173,231
Hedge proceeds	3,574,785			8,198,824			1,253,040			4,576,948

Net proceeds to Trust	$	16,903,294		$	17,973,550		$	8,660,542		$	8,750,179

General and administrative expense	(704,547		)	(948,409		)	(264,042		)	(415,902		)
Interest income	2			424			—			206

Income available for distribution prior to cash reserves and incentive calculation	$	16,198,749		$	17,025,565		$	8,396,500		$	8,334,483

Cash reserves released by Trustee	—			500,000			—			—

Distributable income available to unitholders	$	16,198,749		$	17,525,565		$	8,396,500		$	8,334,483

Distributable income per common unit (17,605,000 common units authorized and outstanding for 2013; 13,203,750 for 2012)	$	0.920		$	1.176		$	0.477		$	0.602
Distributable income per subordinated unit (4,401,250 subordinated units authorized and outstanding for 2012)	$	—		$	0.454		$	—		$	0.088

See notes to the unaudited financial statements.

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ECA Marcellus Trust I

Statements of Trust Corpus

(Unaudited)

	Six Months Ended
	June 30,
	2013			2012
Trust Corpus, Beginning of Period	$	266,966,362		$	304,853,821
Cash reserves released	—			(500,000		)
Distributable income	16,198,749			17,525,565
Distributions paid or payable to unitholders	(16,191,082		)	(17,517,399		)
Amortization of royalty interest in gas properties	(16,202,874		)	(20,005,038		)
Amortization of floor price contracts	(1,221,000		)	(389,400		)

Trust Corpus, End of Period	$	249,550,155		$	283,967,549

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 subsequently 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 (defined herein) 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, all of which are now common units. Prior to December 31, 2012, 13,203,750 were common units and 4,401,250 were 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. As of the formation of the Trust, approximately 50% of the originally estimated natural gas production attributable to the Trust’s Royalty Interests had 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 was obligated to drill all of the PUD Wells no later than March 31, 2014. As of November 30, 2011, ECA had met its drilling obligation and had drilled 52.06 Equivalent PUD Wells, calculated as provided in the Development Agreement. Consequently, the drilling support lien ECA had granted to the Trust in connection with the formation of the Trust to secure ECA’s drilling obligations has been released. The Trust was not responsible for any costs related to the drilling of development wells or any other development or operating costs. The Trust’s cash receipts in respect of the royalties are determined after deducting post-production costs and any applicable taxes associated with the PDP and PUD Royalty Interests. The Trust’s cash available for distribution includes any cash receipts from the floor price contracts and is reduced by Trust administrative expenses. Post-production costs generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Charges (the “Post-Production Services Fee”) payable to ECA for such post-production costs on its Greene County Gathering System were limited to $0.52 per MMBtu gathered until ECA fulfilled its drilling obligation (which it did in November 2011); thereafter, ECA may increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System. Additionally, in the event that electric compression is utilized in lieu of gas as fuel in the compression process, the Trust will be charged for the electric usage as provided for in the Trust conveyance documents.

Generally, the percentage of production proceeds to be received by the Trust with respect to a well will equal the product of (i) the percentage of proceeds to which the Trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) ECA’s net revenue interest in the well. ECA on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the Trust is entitled to receive on average 73.37% of the proceeds of production from the Producing Wells. With respect to the PUD Wells, 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 an example, assuming ECA owns a 100% working interest in a

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PUD well, the applicable net revenue interest is calculated by multiplying ECA’s percentage working interest in the 100% working interest well by the unburdened interest percentage (87.5%) and such well would have a minimum 87.5% net revenue interest. Accordingly, the Trust is entitled to a minimum of 43.75% of the production proceeds from the well provided in this example. 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.

The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting Trust administrative expenses, including the costs incurred as a result of being a publicly traded entity, on or about 60 days following the completion of each quarter. The Trust is expected to liquidate on or about 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 right of first 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 had agreed during the Subordination Period to subordinate 4,401,250 of the Trust units it originally acquired, which constituted 25% of the outstanding Trust units. The subordinated units were entitled to receive pro rata distributions from the Trust each quarter if and to the extent there was sufficient cash to provide a cash distribution on the common units which was at least equal to the applicable quarterly subordination threshold. However, if there was not sufficient cash to fund such a distribution on all Trust units, the distribution with respect to the subordinated units was 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 was 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 exceeded 150% of the subordination threshold for such quarter. ECA’s right to receive the incentive distributions terminated upon the expiration of the Subordination Period.

ECA completed its drilling obligation to the Trust during the fourth quarter of 2011. Consequently, the subordinated units automatically converted into common units on a one-for-one basis on December 31, 2012. Holders of common units no longer have any right to the benefits of the subordination provisions that had been in effect with respect to the subordinated units. The period during which the subordinated units were outstanding is referred to as the “Subordination Period.”

The business and affairs of the Trust are administered by The Bank of New York Mellon Trust Company, N.A. as Trustee. Although ECA operates all of the Producing Wells and all of the PUD Wells, ECA has no ability to manage or influence the management of the Trust. Neither the Trust nor the Trustee has any authority or responsibility for, or any involvement with or influence over, any aspect of the operations on the properties to which the Royalty Interests relate.

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 disclosures 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 months and six months ended June 30, 2013 and 2012 and is therefore subject to adjustment in future periods to reflect actual production for the periods presented.

The information furnished reflects all normal and recurring 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 Trust’s Annual Report on Form 10-K for the year ended December 31, 2012. The December

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31, 2012 condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

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 expired floor price contract premiums does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Amortization of the investment in overriding royalty interests calculated on a unit-of-production basis is charged directly to Trust Corpus. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission as specified by FASB ASC Topic 932 Extractive Activities — Oil and Gas: Financial Statements of Royalty Trusts. Income determined on the basis of GAAP would include all expenses incurred for the period presented. However, the Trust serves as a pass-through entity, with expenses for depreciation, depletion, and amortization, interest and income taxes being based on the status and elections of the Trust unitholders. General and administrative expenses, production taxes or any other allowable costs are charged to the Trust only when cash has been paid for those expenses. In addition, the royalty interest is not burdened by field and lease operating expenses. Thus, the statement shows distributable income, defined as income of the Trust available for distribution to the Trust unitholders before application of those additional expenses, if any, for depreciation, depletion, and amortization, interest and income taxes. The revenues are presented net of existing royalties and overriding royalties and have been reduced by gathering/post-production expenses.

Cash:

Cash may include 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 significantly 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 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 of accounting 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 - Topic 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. Determination as to whether and how much an asset is impaired involves estimates of highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on post-production costs and the outlook for national or regional market supply and demand conditions. If required, the Trust will 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

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Properties. Any such write-down would not reduce Distributable Income, although it would reduce Trust Corpus. No impairment in the Underlying Properties has been recognized since inception of the Trust. 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.

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 originally estimated natural gas to be produced by the Trust properties through March 31, 2014. The swap contracts, which expired on June 30, 2012, 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 quarters ended June 30, 2013 and 2012 totaled $1,253,040 and $4,576,948, respectively. Hedge proceeds realized for the six months ended June 30, 2013 and 2012 totaled $3,574,785 and $8,198,824, respectively. The fair market values of the commodity contracts are not included in the accompanying financial statements, as the statements are presented on a modified cash basis of accounting.

NOTE 5. Income Taxes

The Trust is a Delaware statutory trust, which is taxed as a partnership for federal and state income taxes. Accordingly, no provision for federal or state income taxes has been made.

NOTE 6. Related Party Transactions

Trustee Administrative Fee:

Under the terms of the Trust agreement, the Trust pays an annual administrative fee of $150,000 to the Trustee, which may be adjusted beginning on the fifth anniversary of the Trust as provided in the Trust agreement. These costs, as well as those to be paid to ECA pursuant to the Administrative Services Agreement referred to below, are deducted by the Trust in the period paid.

Administrative Services Fee:

The Trust has 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. 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.

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Drilling Support Lien:

As described in Note 1, ECA granted to the Trust the Drilling Support Lien. The Drilling Support Lien was limited to $91 million, and as ECA fulfilled its drilling obligation over time, the total dollar amount was proportionately reduced. As of November 30, 2011, ECA had fulfilled its drilling obligation and has received a full release of the Drilling Support Lien.

Related Party Ownership:

Pursuant to the terms of the Registration Rights Agreement to which ECA and the Trust are parties, ECA and the Trust have filed a registration statement on Form S-3 pursuant to which ECA may publicly offer and sell common units. The registration statement was declared effective on February 8, 2013. As of June 30, 2013, ECA held a total of 2,824,917 (approximately 16.05%) of the outstanding common units of the Trust.

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, include the private investors. 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 and the audited financial statements and notes thereto included in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2012. The Trust’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available on the SEC’s website at www.sec.gov and also at www.businesswire.com/cnn/ect.htm. Certain terms used herein are defined in Appendix A.

Results of Trust Operations

For the Three Months Ended June 30, 2013 compared to the Three Months Ended June 30, 2012

Distributable income for the three months ended June 30, 2013 increased to $8.4 million from $8.3 million for the three months ended June 30, 2012. Compared to the quarter ended June 30, 2012, royalty income increased $3.2 million, hedge proceeds decreased $3.3 million and general and administrative expenses decreased $0.2 million.

Royalty income increased from $4.2 million for the three months ended June 30, 2012 to $7.4 million for the three months ended June 30, 2013, an increase of $3.2 million. This increase was due to an increase in the average realized price and a decrease in post production costs, partially offset by a decrease in production.

The average price realized for the three months ended June 30, 2013 increased $1.00 per Mcf to $4.27 per Mcf as compared to $3.27 per Mcf for the three months ended June 30, 2012. This increase was the result of an increase in the average sales price for gas production and a decrease in post production costs, partially offset by a decrease in the average hedged price. The average sales price, before the effects of hedges and post production costs, increased from $2.31 per Mcf for the three months ended June 30, 2012 to $4.25 per Mcf for the three months ended June 30, 2013. This increase in price was primarily the result of an increase in the weighted average monthly closing NYMEX price for the current period to $4.09 per MMBtu compared to the quarter ended June 30, 2012 weighted average monthly closing NYMEX price of $2.21 per MMBtu.

Post production costs, which consist of a post-production services fee together with a charge for electricity used in lieu of gas for compression on the gathering system and firm transportation charges on interstate gas pipelines averaged $0.60 per Mcf for the quarter ended June 30, 2013 as compared to an average of $0.75 per Mcf for the prior year’s comparable period.

Post production costs were lower than last year’s comparable quarter primarily as a result of a reduction in the firm transportation rate charged by Columbia Gas Transmission, LLC (“TCO”). Effective March 1, 2013, TCO’s filed tariff rate was reduced from $0.1996 per MMBtu to $0.1878 per MMBtu at one hundred percent load factor.

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For the quarter ended June 30, 2013, the distribution available to all Trust unitholders was $8,396,500, or $0.477 per unit. For the quarter ended June 30, 2012, because the Subordination Threshold for the quarter was $0.602, common unitholders were entitled to a distribution of $0.602 per unit with the subordinated unitholders entitled to a distribution of the remainder at $0.088 per unit. The table below shows the effect of the subordination threshold on the distribution for the quarter ended June 30, 2012:

		For the
		quarter ended
		June 30, 2012
Distributable income available to unitholders		$	8,334,483

Common units outstanding	13,203,750
Subordinated units outstanding	4,401,250	17,605,000
Distributable income per unit before subordination threshold		$	0.473

Subordination threshold per common unit		$	0.602
Common units outstanding		13,203,750
Distributable income payable to common unitholders at subordination threshold level		$	7,948,657

Distributable income available to subordinated unitholders		$	385,826
Subordinated units outstanding		4,401,250
Distributable income per unit available to subordinated unitholders		$	0.088

The Subordination Period terminated on December 31, 2012. Consequently, the fourth quarter of 2012 was the last quarter during which common unitholders had the protection of the subordination provisions. Upon termination of the Subordination Period, the 4,401,750 subordinated units converted to common units. As common units, such 4,401,750 units are now entitled to the same distributions as all other common units, and no common units will be entitled to any benefit formerly conferred upon them by the subordination provisions.

General and administrative expenses paid by the Trust were $0.3 million for the three months ended June 30, 2013 as compared to $0.4 million for the three months ended June 30, 2012. The decrease in expenses was primarily related to a decrease of $0.1 million in Trustee fees paid due to the timing of invoices. The Trustee’s fees for the quarter ended June 30, 2013 were not paid, and it is expected that fees for both the second and third quarters will be paid during the quarter ended September 30, 2013.

ECA completed its drilling obligation as of November 30, 2011. As of June 30, 2013, all forty PUD Wells (52.06 Equivalent PUD Wells) were online and producing.

For the Six Months Ended June 30, 2013 compared to the Six Months Ended June 30, 2012

Distributable income for the six months ended June 30, 2013 decreased to $16.2 million from $17.5 million for the six months ended June 30, 2012. Compared to the six months ended June 30, 2012, royalty income increased $3.5 million, hedge proceeds decreased $4.6 million and general and administrative expenses decreased $0.2 million. During the six months ended June 30, 2012 the Trustee released $0.5 million of cash reserves; no reserves were withheld or released during the six months ended June 30, 2013.

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Royalty income increased from $9.8 million for the six months ended June 30, 2012 to $13.3 million for the six months ended June 30, 2013, an increase of $3.5 million. This increase was due to an increase in the average realized price and a decrease in post production costs, partially offset by a decrease in production.

The average price realized for the six months ended June 30, 2013 increased $0.67 per Mcf to $4.02 per Mcf as compared to $3.35 per Mcf for the six months ended June 30, 2012. This increase was the result of an increase in the average sales price for gas production and a decrease in post production costs, partially offset by a decrease in the average hedged price. The average sales price, before the effects of hedges and post production costs, increased from $2.56 per Mcf for the six months ended June 30, 2012 to $3.85 per Mcf for the six months ended June 30, 2013. This increase in price was primarily the result of an increase in the weighted average monthly closing NYMEX price for the current period to $3.70 per MMBtu compared to the six months ended June 30, 2012 weighted average monthly closing NYMEX price of $2.47 per MMBtu.

Post production costs, which consist of a post-production services fee together with a charge for electricity used in lieu of gas for compression on the gathering system and firm transportation charges on interstate gas pipelines, averaged $0.68 per Mcf for the six months ended June 30, 2013 as compared to an average of $0.74 per Mcf for the prior year’s comparable period.

Post production costs were lower than last year’s comparable six month period primarily as a result of a reduction in the firm transportation rate charged by TCO. Effective March 1, 2013, TCO’s filed tariff rate was reduced from $0.1996 per MMBtu to $0.1878 per MMBtu at one hundred percent load factor. Also, a one-time cash refund of approximately $0.3 million from TCO representing retroactive application of the reduced rate covering the period from January 2012 through February 2013 was received in June 2013.

Production decreased 22% from 5,361 MMcf for the six months ended June 30, 2012 to 4,202 MMcf for the six months ended June 30, 2013. The decreased production was primarily a result of natural production declines, partially offset by an increase in the number of wells online and producing during the six months ended June 30, 2013 compared to the six months ended June 30, 2012 as a result of nine wells being turned online during such prior period. A total of fifty-four wells (14 PDP and 40 PUD Wells (52.06 Equivalent PUD Wells)) were online and producing as of June 30, 2012 and June 30, 2013.

Hedged volumes for the six months ended June 30, 2013 totaled 2,775,000 MMBtu covered by a $5.00 per MMBtu floor price contract. For the six months ended June 30, 2012, hedged volumes totaled 2,250,000 MMBtu consisting of 1,365,500 MMBtu covered by a fixed price swap at a price of $6.82 per MMBtu and 885,000 MMBtu covered by a $5.00 per MMBtu floor price contract resulting in an average hedge price of approximately $6.10 per MMBtu for the hedged volume. The average hedge price per MMBtu declined from $6.10 per MMBtu for the six months ended June 30, 2012 to $5.00 per MMBtu for the six months ended June 30, 2013 due to the expiration of the swap contracts. Although there was an increase in volumes covered by hedge contracts, proceeds received by the Trust for the six months ended June 30, 2013 of $3.6 million, as compared to $8.2 million for the six months ended June 30, 2012 decreased as a result of the decrease in hedge price and the increase in the average NYMEX price as discussed previously.

The fixed price swap contracts terminated June 30, 2012. The floor hedging arrangements terminate March 31, 2014. Distributions after the hedging arrangements terminate may be substantially more volatile, and could, depending on natural gas prices, be substantially lower or higher than those during the period that the hedging arrangements are in effect.

General and administrative expenses paid by the Trust were $0.7 million for the six months ended June 30, 2013 as compared to $0.9 million for the six months ended June 30, 2012. The decrease in expenses was primarily related to a decrease of $0.1 million in professional tax service fees paid and a decrease of $0.1 million in legal fees.

Prior to 2012, the Trustee had established a net cash reserve of $500,000 for use in paying current and future liabilities of the Trust as they become due. The Trustee released the cash reserve during the six months ended June 30, 2012, but may re-establish a reserve of any amount at any time. The release of the cash reserve increased distributable income for the six months ended June 30, 2012.

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ECA completed its drilling obligation as of November 30, 2011. As of June 30, 2013, all forty PUD Wells (52.06 Equivalent PUD Wells) were online and producing.

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 “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” regarding the financial position, business strategy, production and reserve growth, development activities and costs and other plans and objectives for the future operations of ECA and all matters relating to the Trust are forward-looking statements. Actual outcomes and results may differ materially from those projected.

When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions, are intended to identify such forward-looking statements. Further, all statements regarding future circumstances or events are forward-looking statements. The following important factors, in addition to those discussed elsewhere in this document, could affect the future results of the energy industry in general, and ECA and the Trust in particular, and could cause those results to differ materially from those expressed in such forward-looking statements:

· risks incident to the operation of natural gas wells;

· future production costs;

· the effects of existing and future laws and regulatory actions;

· the effects of changes in commodity prices;

· the ability of the Trust’s hedge counterparties to meet their contractual obligations;

· conditions in the capital markets;

· competition in the energy industry;

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

· other risks described under the caption “Risk Factors” in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2012.

This Form 10-Q describes other important factors that could cause actual results to differ materially from expectations of ECA and the Trust, including those referenced in Item 1A of Part II under the caption “Risk Factors.” All subsequent written and oral forward-looking statements attributable to ECA or the Trust or persons acting on behalf of ECA or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.

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 Royalty Interests (described below), to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalty Interests after payment of Trust expenses, and to perform certain administrative functions in respect of the Royalty Interests and the Trust units. The Trustee has no authority or responsibility for, and no involvement with, any aspect of the oil and gas operations on the properties to which the Royalty Interests relate. The Trust derives all or substantially all of its income and cash flows from the Royalty Interests, which in turn are subject to the hedge contracts described in Part I, Item 3. The Trust is treated as a partnership for federal and state income tax purposes.

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ECA completed its drilling obligation to the Trust under the Development Agreement as of November 30, 2011. This completion date was approximately 2.3 years in advance of the required completion date of March 31, 2014. Consequently, no additional wells will be drilled for the Trust, and the subordinated units automatically converted on a one-for-one basis into ECT Common Units on December 31, 2012. The last cash distribution supported by the ECT Subordinated Units was the cash distribution payable with respect to the proceeds for the fourth quarter of 2012, which was paid on February 28, 2013. Beginning with the cash distribution payable with respect to the first quarter of 2013, all ECT trust units share in all cash distributions on a pro rata basis. As of June 30, 2013 the Trust owns royalties in the 14 Producing Wells and the forty development wells (52.06 Equivalent PUD Wells calculated in accordance with the Development Agreement and as described in the Prospectus) that are now completed and in production.

The royalty interests were conveyed from ECA’s working interest in the Producing Wells and the PUD Wells limited to the Underlying Properties. The royalty interest in the Producing Wells 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 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 Royalty Interests has been hedged through March 31, 2014.

ECA was obligated to drill all of the PUD Wells by March 31, 2014. As of November 30, 2011, ECA had fulfilled its drilling obligation to the Trust by drilling 40 PUD Wells (52.06 Equivalent PUD Wells), calculated as provided in the Development Agreement. The Trust was not responsible for any costs related to the drilling of development wells or any other development or operating costs. The Trust’s cash receipts in respect of the Royalties is determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests, and the Trust’s cash available for distribution includes any cash receipts from the hedge contracts and is reduced by Trust administrative expenses. Post-production costs generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Charges payable to ECA for such post-production costs on its Greene County Gathering System were limited to $0.52 per MMBtu gathered until ECA fulfilled its drilling obligation; thereafter, ECA may increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System.

Generally, the percentage of production proceeds to be received by the Trust with respect to a well equals the product of (i) the percentage of proceeds to which the Trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) ECA’s net revenue interest in the well. ECA on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the Trust is entitled to receive on average 73.37% of the proceeds of production from the Producing Wells. With respect to the PUD Wells, 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 an example, assuming ECA owns a 100% working interest in a PUD Well, the applicable net revenue interest is calculated by multiplying ECA’s percentage working interest in the 100% working interest well by the unburdened interest percentage (87.5%), and such well would have a minimum 87.5% net revenue interest. Accordingly, the Trust is entitled to a minimum of 43.75% of the production proceeds from the well provided in this example. 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.

The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting Trust administrative expenses and costs and reserves therefor, on or about 60 days following the completion of each quarter. The first quarterly distribution was made on August 31, 2010 to record unitholders as of August 16, 2010. The Trust is expected to terminate in 2030.

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The amount of Trust revenues and cash distributions to Trust unitholders will depend on, among other things:

· natural gas prices received;

· the volume and Btu rating of natural gas produced and sold;

· post-production costs and any applicable taxes;

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

· the effects of the hedging arrangements, and the expiration of the hedging arrangements.

The amount of the quarterly distributions will fluctuate from quarter to quarter, depending on the proceeds received by the Trust, among other factors. There is no minimum required distribution. In order to provide support for cash distributions on the common units for a limited period of time, ECA agreed to subordinate 4,401,250 of the Trust units it originally acquired, which constituted 25% of the outstanding Trust units. The subordinated units were entitled to receive pro rata distributions from the Trust each quarter if and to the extent there was sufficient cash to provide a cash distribution on the common units which was at least equal to the applicable quarterly subordination threshold. However, if there was not sufficient cash to fund such a distribution on all Trust units, the distribution with respect to the subordinated units was 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 was 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 exceeded 150% of the subordination threshold for such quarter. ECA’s right to receive the incentive distributions, and the benefits of the subordination provision to the holders of common units, terminated upon the expiration of the Subordination Period.

The subordinated units automatically converted into common units on a one-for-one basis and ECA’s right to receive incentive distributions terminated on December 31, 2012. Because the Subordination Period terminated on December 31, 2012, the fourth quarter of 2012 was the last quarter that the common unitholders were eligible to receive a distribution in the amount of the Subordination Threshold. The table below sets forth the Target Distributions and the Subordination and Incentive Thresholds for each quarter through the fourth quarter of 2012.

The effective date of the Trust was April 1, 2010, meaning the Trust 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.

	Subordination		Target		Incentive
	Threshold		Distribution		Threshold

2010:
Second Quarter	$	0.181	$	0.227	$	0.272
Third Quarter	0.334		0.417		0.501
Fourth Quarter	0.478		0.597		0.716
2011:
First Quarter	0.446		0.558		0.669
Second Quarter	0.451		0.564		0.676
Third Quarter	0.550		0.688		0.825
Fourth Quarter	0.565		0.706		0.847
2012:
First Quarter	0.574		0.717		0.861
Second Quarter	0.602		0.752		0.903
Third Quarter	0.624		0.780		0.937
Fourth Quarter	0.701		0.876		1.051

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Pursuant to IRC Section 1446, withholding tax on income effectively connected to a United States trade or business allocated to foreign partners should be made at the highest marginal rate. Under Section 1441, withholding tax on fixed, determinable, annual, periodic income from United States sources allocated to foreign partners should be made at 30% of gross income unless the rate is reduced by treaty. This release is intended to be a qualified notice to nominees and brokers as provided for under Treasury Regulation Section 1.1446-4(b) by ECA Marcellus Trust I, and while specific relief is not specified for Section 1441 income, this disclosure is intended to suffice. Nominees and brokers should withhold 39.6% of the distribution made to foreign partners.

Liquidity and Capital Resources

The Trust has no source of liquidity or capital resources other than cash flows from the Royalty Interests. Other than Trust administrative expenses, including, if applicable, expense reimbursements to ECA and any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. 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 Royalty Interests and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust’s expenses for that quarter. 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 Royalty Interests are based on the complex provisions of the various conveyances held by the Trust, copies of which are filed as exhibits to this report, and reference is hereby made to the text of the conveyances for the actual calculations of amounts due to the Trust.

The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.

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 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 shows distributable income, defined as income of the Trust available for distribution to the Trust unitholders before application of those unitholders’ additional expenses, if any, for depreciation, depletion, and amortization, interest and income taxes. The revenues are reflected net of existing royalties and overriding royalties and have been reduced by gathering/post-production expenses.

Revenue and Expenses:

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Income 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 - Topic 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 be required to write down assets 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. No impairment in the Underlying Properties has been recognized since inception of the Trust. Significant dispositions or abandonment of the Underlying Properties are charged to Royalty Interests and the Trust Corpus.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Hedge Contracts

The primary asset of and source of income to the Trust are the Royalty Interests, which generally entitle the Trust to receive varying portions of the net proceeds from gas production from the Underlying Properties. Consequently, the Trust is exposed to market risk from fluctuations in gas prices. Through March 31, 2014, however, the Royalties are subject to the hedge contracts described below, which are expected to reduce the Trust’s exposure to natural gas price volatility.

Current hedge contracts consist of natural gas derivative floor price contracts ECA entered into and subsequently conveyed to the Trust to provide the Trust with the economic effects of certain contracts previously entered into between ECA and third parties that equate to approximately 50% of the remaining natural gas originally estimated in connection with the formation of the Trust to be produced by the Trust properties from April 1, 2013 through March 31, 2014. The floor price under the hedging contracts, which expire in the first quarter of 2014, is $5.00 per MMBtu.

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The following table sets forth the volumes of natural gas covered by the natural gas hedging contracts and the floor price for each quarter during the term of the contracts.

	Swap Volume	Swap Price		Floor Volume	Floor Price
	(MMBtu)	(MMBtu)		(MMBtu)	(MMBtu)

Second Quarter 2010	682,500	$	6.75	—	—
Third Quarter 2010	690,000	$	6.75	—	—
Fourth Quarter 2010	690,000	$	6.75	225,000	$	5.00
First Quarter 2011	675,000	$	6.75	159,000	$	5.00
Second Quarter 2011	682,500	$	6.75	210,000	$	5.00
Third Quarter 2011	690,000	$	6.82	405,000	$	5.00
Fourth Quarter 2011	690,000	$	6.82	384,000	$	5.00
First Quarter 2012	682,500	$	6.82	369,000	$	5.00
Second Quarter 2012	682,500	$	6.82	516,000	$	5.00
Third Quarter 2012				1,305,000	$	5.00
Fourth Quarter 2012				1,362,000	$	5.00
First Quarter 2013				1,395,000	$	5.00
Second Quarter 2013				1,380,000	$	5.00
Third Quarter 2013				1,278,000	$	5.00
Fourth Quarter 2013				1,188,000	$	5.00
First Quarter 2014				1,092,000	$	5.00

The Trust’s counterparties under the natural gas floor price contracts are Wells Fargo Capital Finance 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 has no continuing obligations with respect to the natural gas floor price contracts.

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 promulgated by the SEC. Disclosure controls and procedures include 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.

Due to the nature of the Trust, there are certain potential weaknesses that may limit the effectiveness of the disclosure controls and procedures established by the Trustee. The limitations include the facts that:

· ECA and its consolidated subsidiaries manage virtually all of the information relating to the Trust, including all information regarding (i) historical operating data, production volumes, the number of producing wells and acreage, the marketing and sale of production, operating and capital expenditures, environmental matters and other potential expenses and liabilities, and the effects of regulatory matters and changes, (ii) plans for future operating and capital expenditures and (iii) geological data relating to reserves, and the Trustee necessarily relies on ECA for all such information; and

· The Trustee necessarily relies upon the independent reserve engineer as an expert with respect to the annual reserve report, which includes projected production, operating expenses and capital expenses.

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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.

	ECA MARCELLUS TRUST I

	By:	THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., trustee


		By:	/s/ MIKE ULRICH
			Mike Ulrich
			Vice President


Date: August 9, 2013

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 Number		Description
3.1		Certificate of Trust of ECA Marcellus Trust I (Incorporated herein by reference to Exhibit 3.4 to Registration Statement on Form S-1 (Registration No. 333-165833))
3.2		Amended and Restated Trust Agreement of ECA Marcellus Trust I, dated July 7, 2010, by and among Energy Corporation of America, The Bank of New York Mellon Trust Company, N.A., as Trustee, and Corporation Trust Company, as Delaware Trustee. (Incorporated herein by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800))
10.1*		Perpetual Overriding Royalty Interest Conveyance (PDP), dated effective April 1, 2010, from Energy Corporation of America to The Bank of New York Mellon Trust Company, N.A., as Trustee.
10.2*		Perpetual Overriding Royalty Interest Conveyance (PUD), dated effective April 1, 2010, from Energy Corporation of America to The Bank of New York Mellon Trust Company, N.A., as Trustee.
10.3*		Private Investor Conveyance, dated July 7, 2010, by and among ECA Marcellus Trust I and certain private investors named therein
10.4*		Assignment of Royalty Interest, dated effective April 1, 2010, from Eastern Marketing Corporation to The Bank of New York Mellon Trust Company, N.A., as Trustee.
10.5*		Term Overriding Royalty Interest Conveyance (PDP), dated effective April 1, 2010, from Energy Corporation of America to Eastern Marketing Corporation.
10.6*		Term Overriding Royalty Interest Conveyance (PUD), dated effective April 1, 2010, from Energy Corporation of America to Eastern Marketing Corporation.
10.7*		Administrative Services Agreement, dated July 7, 2010, by and between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee
10.8*		Development Agreement, dated July 7, 2010, by and between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee.
10.9*		Swap Agreement, dated July 7, 2010, by and between Energy Corporation of America and ECA Marcellus Trust I.
10.10*		Drilling Support Lien Agreement, dated July 7, 2010, by and between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A.
10.11*		Royalty Interest Lien Agreement, dated July 7 2010, by and between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee.
10.12*		Registration Rights Agreement, dated July 7, 2010, by and among ECA Marcellus Trust I, Energy Corporation of America, and certain affiliates of Energy Corporation of America.
10.13		Underwriting Agreement dated as of June 30, 2010, by and among Energy Corporation of America, ECA Marcellus Trust I, and the underwriters named therein (Incorporated herein by reference to Exhibit 1.1 to the Trust’s Current Report on Form 8-K filed on July 6, 2010 (File No. 001-34800)).
10.14		Underwriting Agreement dated as of April 12, 2011, by and among Energy Corporation of America, ECA Marcellus Trust I, and the underwriters named therein (Incorporated herein by reference to Exhibit 1.1 to the Trust’s Current Report on Form 8-K filed on April 15, 2011 (File No. 001-34800)).
31		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*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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APPENDIX A

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.

AMI - The area of mutual interest, or AMI, consisted of the Marcellus Shale formation in approximately 121 square miles of property located in Greene County, Pennsylvania in which ECA had leased approximately 9,300 acres and owned substantially all of the working interests at the date of formation of the Trust. ECA was obligated to drill the 52 development wells from drill sites on approximately 9,300 leased acres in the AMI. Until ECA satisfied its drilling obligation on November 30, 2011, it was not permitted to drill and complete any well in the Marcellus Shale formation within the AMI for its own account.

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.

Equivalent PUD Well - is defined as a well that is drilled horizontally in the Marcellus formation for a lateral distance of 2,500 feet measured from the midpoint of the curve to the end of the lateral multiplied by the working interest held by ECA. Wells with a horizontal lateral less than 2,500 feet count as fractional wells in proportion to the total lateral length divided by 2,500 feet. Wells with a horizontal lateral greater than 2,500 feet (subject to a maximum of 3,500 feet) count as fractional wells in proportion to the total lateral length divided by 2,500 feet.

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 end of the Subordination Period, 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 originally acquired, 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 was 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 exceeded 150% of the subordination threshold for such quarter. ECA’s right to receive the incentive distributions terminated upon the expiration of the Subordination Period.

MMBtu - One million British Thermal Units.

Mcf - One thousand cubic feet of natural gas.

MMcf - One million 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 - the prospectus dated July 1, 2010 and filed with the SEC pursuant to rule 424(b) on July 1, 2010 relating to the initial public offering of the Trust units.

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.

PART I — Financial Information
Item 1. Financial Statements (Unaudited)		3
	Statement of Assets, Liabilities and Trust Corpus as of June 30, 2013 and December 31, 2012	3
	Statement of Distributable Income for the Three Months and Six Months Ended June 30, 2013 and 2012	4
	Statement of Trust Corpus for the Six Months Ended June 30, 2013 and 2012	5
	Notes to Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		10
Item 3. Quantitative and Qualitative Disclosures About Market Risk		18
Item 4. Controls and Procedures		19

PART II- Other Information
Item 1A. Risk Factors		21
Item 6. Exhibits		21
	SIGNATURES	22
	EXHIBIT INDEX	23
APPENDIX A
Glossary of Certain Terms		24