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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, 2017

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)

(512) 236-6555
(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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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 8, 2017, 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)

See notes to the unaudited financial statements.

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ECA Marcellus Trust I

Statements of Distributable Income

(Unaudited)

See notes to the unaudited financial statements.

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ECA Marcellus Trust I

Statements of Trust Corpus

(Unaudited)

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, (the “AMI”) comprising 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.  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.

ECA was obligated to drill 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 Royalty Interests are determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests.  The Trust’s cash available for distribution 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 the 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, if 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 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 is proportionately reduced.

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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.  Unless sooner liquidated, the Trust is scheduled to liquidate on or about March 31, 2030 (the “Termination Date”). At the termination of the Trust, 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 of the Trust. ECA will have a right of first refusal to purchase the remaining 50% of the Royalty Interests at the termination of the Trust.

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 or relating to 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 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- and nine-month periods ended September 30, 2017 and 2016 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, 2016. The December 31, 2016 condensed balance sheet data was derived from audited financial statements, but does not include all applicable financial statement disclosures.

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 (“SEC”) as specified by Accounting Standard Codification (“ASC”) 932 Extractive Activities—Oil and Gas: Financial Statements of Royalty Trusts (“ASC 932”).  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 maturing in three months or less from the date acquired.

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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 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 Interest in gas properties is assessed to determine whether the net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to ASC 360, Property, Plant and Equipment (“ASC 360”). The Trust determines whether an impairment charge is necessary to its investment in the Royalty Interests in gas properties if 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, weighted average cost of capital, and technology improvements on post-production costs and the outlook for national or regional market supply and demand conditions. If required, the Trust will recognize an impairment charge to the extent that the net capitalized costs exceed the discounted fair value of the investment in net profits interests attributable to proved gas reserves of the Underlying Properties. Any such impairment charge would not reduce Distributable Income, although it would reduce Trust Corpus.  At December 31, 2016, the undiscounted future net revenues exceeded the Net royalty interest in the gas properties, and therefore no impairment was necessary during the year. No impairment in the Underlying Properties has been recognized during 2017.  Significant dispositions or abandonment of the Underlying Properties are charged to Royalty Interests and the Trust Corpus.

Amortization of the Royalty Interest 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 Interest 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.  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. Uncertain tax positions are accounted for under ASC 740, Income Taxes (“ASC 740”), which prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. Additionally, ASC 740 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.  The Trust has not identified any uncertain tax positions through the period ended September 30, 2017.

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NOTE 5.  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. Although the Trust Agreement permits this fee to be adjusted annually beginning on the fifth anniversary of the Trust, January 1, 2016, the fee has remained unchanged through September 30, 2017.  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 and ECA are parties to an Administrative Services Agreement 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.

Cash Advance:

Pursuant to a letter agreement between the Trustee and ECA, the Trustee is permitted to make funding requests of ECA on behalf of the Trust for use in paying current and future liabilities of the Trust as they become due. ECA made no additional advances to the Trust during the quarters ended September 30, 2017 or 2016.

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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, 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, 2016. 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.

Note Regarding Forward-Looking Statements

This report 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 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;

·                  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, 2016.

This report 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

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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. The Trust is treated as a partnership for federal and state income tax purposes.

ECA completed its drilling obligation to the Trust under the Development Agreement as of November 30, 2011. The Trust was not responsible for any costs related to the drilling of development wells or any other development or operating costs. Consequently, no additional wells will be drilled for the Trust.  As of September 30, 2017, the Trust owns royalty interests in the 14 Producing Wells and the 40 development wells (52.06 Equivalent PUD Wells calculated in accordance with the Development Agreement) 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 PDP Royalty Interest entitles the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells for a period of 20 years commencing on April 1, 2010 and 45% thereafter. The PUD Royalty Interest entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter.

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 Royalty Interests are determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests, and the Trust’s cash available for distribution is also reduced by Trust administrative expenses and any amounts reserved for 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 the related Greene County Gathering System were limited to $0.52 per MMBtu gathered until ECA fulfilled its drilling obligation in 2011; since then, ECA has been permitted to 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.  Unless sooner terminated, the Trust will terminate in March 2030.

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

·                  natural gas prices received;

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

·                  post-production costs and any applicable taxes; and

·                  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.

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.

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.

Results of Trust Operations

For the Three Months Ended September 30, 2017 compared to the Three Months Ended September 30, 2016

Distributable income for the three months ended September 30, 2017 increased to $1.3 million from $1.2 million for the three months ended September 30, 2016.  Compared to the quarter ended September 30, 2016, royalty income increased by $0.1 million and general and administrative expenses remained relatively flat in the current period.

Royalty income increased from just under $1.4 million for the three months ended September 30, 2016 to just over $1.4 million for the three months ended September 30, 2017, an increase of approximately $0.1 million.  This increase was due to an increase in the average sales price partially offset by natural production declines.

The average price realized for the three months ended September 30, 2017 increased $0.34 per Mcf to $2.35 per Mcf as compared to $2.01 for the three months ended September 30, 2016.  The increase in the average sales price for natural gas production was due to an increase in the weighted average monthly closing NYMEX price as well as an improved basis.  The increase in the average sales price for natural gas production was primarily the result of an increase in the weighted average monthly closing NYMEX price for the current period to $3.01 per MMBtu compared to the weighted average monthly closing NYMEX price of $2.81 per MMBtu for the three months ended September 30, 2016.  The average Basis per MMBtu for the three months ended September 30, 2017, was more favorable at minus $0.76 per MMBtu compared to the prior period Basis of minus $0.88 per MMBtu.

Post-production costs 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 and, since July 2013, an additional gathering charge for system enhancements applicable to certain wells in an effort to increase production by reducing the high line pressure previously experienced by those wells. Overall, average post-production costs increased $0.02 from $0.75 per Mcf for the three-month period ended September 30, 2016, to $0.77 per Mcf for the three-month period ended September 30, 2017. During the three months ended September 30, 2017, there was an increase in electricity usage charges and firm transportation fees offset by lower post-production services gathering fees related to certain capital expenditures associated with new system enhancements to increase the daily flow rate on lower-producing well pads by reducing the existing line pressure.

Production decreased 15% from 1,076 MMcf for the three months ended September 30, 2016 to 918 MMcf for the three months ended September 30, 2017. The decreased production was primarily a result of natural production declines that occur during the life of a well.

General and administrative expenses paid by the Trust remained relatively flat at $0.1 million for each period.

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For the Nine Months Ended September 30, 2017 compared to the Nine Months Ended September 30, 2016

Distributable income for the nine months ended September 30, 2017 increased to $4.5 million from $2.2 million for the nine months ended September 30, 2016.  Compared to the nine months ended September 30, 2016, royalty income increased by $2.2 million and general and administrative expenses decreased by $0.1 million in the current period.

Royalty income increased from $3.3 million for the nine months ended September 30, 2016 to $5.5 million for the nine months ended September 30, 2017, an increase of $2.2 million.  This increase was due to an increase in the average sales price partially offset by natural production declines.

The average price realized for the nine months ended September 30, 2017 increased $1.00 per Mcf to $2.71 per Mcf as compared to $1.71 for the nine months ended September 30, 2016.  The increase in the average sales price for natural gas production was due to an increase in the weighted average monthly closing NYMEX price.  The increase in the average sales price for natural gas production was primarily the result of an increase in the weighted average monthly closing NYMEX price for the current period to $3.17 per MMBtu compared to the weighted average monthly closing NYMEX price of $2.28 per MMBtu for the nine months ended September 30, 2016. The average Basis per MMBtu in the current nine-month period was more favorable at minus $0.56 per MMBtu compared to the prior period Basis of minus $0.64 per MMBtu.

Post-production costs 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 and, since July 2013, an additional gathering charge for system enhancements applicable to certain wells in an effort to increase production by reducing the high line pressure previously experienced by those wells. Overall, average post-production costs decreased $0.01 from $0.70 per Mcf for the nine-month period ended September 30, 2016, to $0.69 per Mcf for the nine-month period ended September 30, 2017. During the nine months ended September 30, 2017, there was a decrease in  post-production services gathering fees related to certain capital expenditures associated with new system enhancements to increase the daily flow rate on lower-producing well pads by reducing the existing line pressure, offset by a slight increase in electricity usage charges during the period.

Production decreased 17% from 3,303 MMcf for the nine months ended September 30, 2016 to 2,736 MMcf for the nine months ended September 30, 2017. The decreased production was primarily a result of natural production declines that occur during the life of a well.

General and administrative expenses paid by the Trust decreased $0.1 million from $1.1 million for the nine-month period ended September 30, 2016, to $1.0 million for the nine-month period ended September 30, 2017.

Liquidity and Capital Resources

The Trust has no source of liquidity or capital resources other than net 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, on behalf of the Trust, 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 the Trust’s Annual Report on Form 10-K for

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the year ended December 31, 2016, 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, among other differences, 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 SEC as specified by ASC 932.

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 Interests are 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:

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 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 Interest in gas properties is assessed to determine whether the net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to ASC 360. The Trust determines whether an impairment charge is necessary to its investment in the Royalty Interest in gas properties if 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, weighted average cost of capital, and technology improvements on post-production costs and the outlook for national or regional market supply and demand conditions. Estimates of undiscounted future net revenues attributable to proved gas reserves utilize NYMEX forward pricing curves, adjusted for the basis differential. If required, the Trust will recognize an impairment charge to the extent that the net capitalized costs exceed the discounted fair value of the investment in net profits interests attributable to proved gas reserves of the Underlying Properties. Any such impairment charge would not reduce Distributable Income, although it would reduce Trust Corpus.  At December 31, 2016, the undiscounted future net revenues exceeded the Net royalty interest in gas properties, and therefore no impairment was recognized during the year then ended.  No impairment in the Underlying Properties has been recognized during 2017.  Significant dispositions or abandonment of the Underlying Properties are charged to Royalty Interests and the Trust Corpus.

Amortization of the Royalty Interest 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.

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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 Interest 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.

Exposure to Natural Gas Prices

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 natural gas production from the Underlying Properties. Consequently, the Trust is exposed to market risk from fluctuations in natural gas prices.

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 Exchange Act of 1934, as amended (the “Act”), 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. Sarah Newell, 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.

Other than reviewing the financial and other information provided to the Trust by ECA and the independent reserve engineer, the Trustee has made no independent or direct verification of this financial or other information.

The Trustee does not intend to expand its responsibilities beyond those permitted or required by the Trust Agreement and those required under applicable law.

The Trustee does not expect that the Trustee’s disclosure controls and procedures or the Trustee’s internal control over financial reporting will prevent all errors or all fraud. Further, the design of disclosure controls and procedures and internal control over financial reporting must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.

Changes in Internal Control over Financial Reporting. During the quarter ended September 30, 2017, 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

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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.

PART II-OTHER INFORMATION

Item 1A. Risk Factors.

Risk factors relating to the Trust are contained in Item 1A of the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.  No material changes to such risk factors have occurred since the filing of such report.

Item 6. Exhibits.

The following exhibits are filed or furnished as part of this Quarterly Report on Form 10-Q:

EXHIBIT INDEX

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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 9, 2017

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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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.

Basis — The difference between the spot or cash price and the futures price of the same or related commodity.  For natural gas, basis equals the local cash market price minus the price of the nearby NYMEX natural gas futures contract.

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.

Development Agreement - An agreement under which ECA was obligated to drill all of the PUD Wells no later than March 31, 2014.  In order to secure the estimated amount of the drilling costs for the Trust’s interests in the PUD Wells, ECA granted to the Trust a lien on ECA’s interest in the Marcellus Shale formation in the AMI, excluding the Producing Wells and any other wells which were producing and not subject to the Royalty Interests.

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.

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.

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.

Working Interest - The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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