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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549



FORM 10-K



(Mark One)ý

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934for the fiscal year ended December 31, 2017o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934for the transition period
from                                    to


Commission File Number 001-34800



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



Delaware(State or other jurisdiction of
incorporation or organization)

27-6522024(I.R.S. Employer
Identification No.)The Bank of New York MellonTrust Company, N.A.,TrusteeGlobal Corporate Trust601 Travis Street, 16th FloorHouston, Texas(Address of principal executive offices)

77002(Zip Code)


Registrant's
telephone number, including area code:(512) 236-6555

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



Title of Each Class

Name of Each Exchange on which RegisteredUnits of Beneficial Interest

New York Stock Exchange


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

None(Title of class)

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

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

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

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

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

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



Large accelerated filer o

Accelerated filer o

Non-accelerated filer ý (Do not check if a
smaller reporting company)

Smaller reporting company o Emerging growth Company o


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
Act). Yes o    No ý

The aggregate market value of Common Units representing beneficial interests in ECA Marcellus Trust I held by non-affiliates on June 30, 2017, the last
business day of the registrant's most recently completed second fiscal quarter, was $36,970,500.

As
of March 16, 2018, 17,605,000 Common Units representing beneficial interests in ECA Marcellus Trust I were outstanding.

Documents Incorporated By Reference: None





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TABLE OF CONTENTS





Forward-Looking Statements


3Glossary of Certain Oil and Natural Gas Terms


3PART IItem 1.

Business


7Item 1A.

Risk Factors


22Item 1B.

Unresolved Staff Comments


39Item 2.

Properties


39Item 3.

Legal Proceedings


45Item 4.

Mine Safety Disclosures


45PART IIItem 5.

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


46Item 6.

Selected Financial Data


47Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations


47Item 7A.

Quantitative and Qualitative Disclosure About Market Risk


53Item 8.

Financial Statements and Supplementary Data


54Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


64Item 9A.

Controls and Procedures


64Item 9B.

Other Information


65PART IIIItem 10.

Directors, Executive Officers and Corporate Governance


66Item 11.

Executive Compensation


66Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters


66Item 13.

Certain Relationships and Related Transactions and Director Independence


66Item 14.

Principal Accounting Fees and Services


67PART IVItem 15.

Exhibits, Financial Statement Schedules


68Item 16.

Form 10-K Summary


68SIGNATURES


69Appendix A. Report of Ryder Scott Company, L.P.


A-1


References
to the "Trust" in this document refer to ECA Marcellus Trust I. As discussed in Item 1Business"Introduction," Greylock Energy, LLC,
acquired substantially all of the assets of Energy Corporation of America in November 2017. References to "Greylock" in this document refer to Greylock Energy, LLC, and certain of its
wholly-owned subsidiaries. References to "Legacy ECA" refers to Energy Corporation of America and its wholly-owned subsidiaries, and when discussing the conveyance documents the Private Investors, as
it existed prior to the asset acquisition by Greylock.

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains "forward-looking statements" about Greylock 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 Greylock 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 Greylock and the Trust in particular, and could cause those results to differ materially from those expressed in such forward-looking
statements:



This
report describes other important factors that could cause actual results to differ materially from expectations of Greylock and the Trust, including under the caption "Risk
Factors." All subsequent written and oral forward-looking statements attributable to Greylock or the Trust or persons acting on behalf of Greylock 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.

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. Certain
references made to Legacy ECA reflect historical actions or operations that preceded Greylock's acquisition of substantially all of Legacy ECA's assets.

AMIThe area of mutual interest, or AMI, consisting of the Marcellus Shale formation in approximately 121 square miles of property located in Greene
County, Pennsylvania in which Legacy ECA had leased approximately 9,300 acres and owned substantially all of the working interests at the date of formation of the Trust. Legacy ECA was obligated to
drill the 52 development wells from drill sites on approximately 9,300 leased acres in the AMI. Until Legacy 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.

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BcfOne billion cubic feet of natural gas.

BtuA British Thermal Unit, a common unit of energy measurement.

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 Legacy 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, Legacy ECA granted to the Trust a lien on Legacy 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.

Legacy ECA's retained interestLegacy ECA's retained interest in 10% of the proceeds from the sale of production from the 14 producing Marcellus Shale
natural gas wells located in Greene County, Pennsylvania as well as Legacy ECA's retained interest in 50% of the proceeds from the sale of production from the PUD Wells drilled in the AMI. This
interest was conveyed to Greylock from Legacy ECA as part of the asset acquisition as described in Item 1Business"Introduction" below.

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 Legacy ECA. Wells with a horizontal lateral less than 2,500 feet count as a fractional well in proportion
to 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) will count as Fractional Wells in proportion to the total
lateral length divided by 2,500 feet.

Farmout agreementA farmout agreement is typically an agreement under which a lessee
under an oil and gas lease agrees to grant to another party the right to drill wells on the tract covered by such lease and to earn certain acreage for drilling such wells.

FASB ASCmeans the Financial Accounting Standards Board Accounting Standards Codification.

Fractional wellThe fraction (either greater than one or less than one) of a well obtained by dividing the horizontal lateral (measured from the
midpoint of the curve) of such well by 2,500 feet (subject to a maximum of 3,500 feet).

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.

Net Profits InterestA non-operating interest that creates a share in gross production from an operating or working interest in oil and natural gas
properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

Perpetual PDP Royalty Interestsmeans the interests entitling holders to receive 45% of the proceeds from the sale of production of natural gas
attributable to the interests of Legacy ECA in the Producing Wells (after deducting post-production costs and any applicable taxes).

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Perpetual PUD Royalty Interestsmeans the interests entitling holders to receive 25% of the proceeds from the sale of production of natural gas
attributable to Legacy ECA's interest in the PUD Wells (after deducting post-production costs and any applicable taxes).

Perpetual Royalty Interestsa term that collectively references the Perpetual PDP Royalty Interests and the Perpetual PUD Royalty Interests.

Private Investorsthe persons described as the "Private Investors" in the Prospectus.

Prospectusthe prospectus dated July 1, 2010 and filed with the SEC pursuant to Rule 424(b) on July 1, 2010 relating to the
initial public offering of the Trust Units.

Proved developed reservesReserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reservesUnder SEC rules proved reserves are defined as:

Those
quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically produciblefrom a given
date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulationsprior to the time at which contracts providing the right to
operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the
hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes
(i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be
continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a
reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with
reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be
assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when
(i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir
or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the
project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility
from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted
arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

SECmeans the United States Securities and Exchange Commission.

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

Subject Interestmeans Greylock's current undivided interests in the AMI, as lessee under Gas leases, as an owner of the Subject Gas (or the right to
extract such Gas), or otherwise, by virtue of

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which
undivided interests Greylock has the right to conduct exploration and natural gas production operations on the AMI.

Term PDP Royalty Interestsmeans the interests entitling holders to receive 45% of the proceeds from the sale of production of natural gas
attributable to Legacy ECA's interest in the Producing Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010.

Term PUD Royalty Interestsmeans the interests entitling holders to receive 25% of the proceeds from the sale of production of natural gas
attributable to Legacy ECA's interest in the PUD Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010.

Term Royalty Interestsa term that collectively references the Term PDP Royalty Interests and the Term PUD Royalty Interests.

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

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

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PART I

Item 1.Business

Introduction

ECA Marcellus Trust I is a statutory trust formed in March 2010 under the Delaware Statutory Trust Act, pursuant to a Trust Agreement, as
amended and restated (the "Trust Agreement"), among Energy Corporation of America ("Legacy ECA"), as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the "Trustee"), and
Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee"). The Trust maintains its offices at the office of the Trustee, at 601 Travis Street, 16th Floor, Houston
Texas 77002. The telephone number of the Trustee is 1-512-236-6555.

In
November 2017, Greylock Energy, LLC, and certain of its wholly owned subsidiaries ("Greylock") acquired substantially all of the gas production and midstream assets of Legacy
ECA, including all of Legacy ECA's interests in certain natural gas properties that are subject to royalty interests held by the Trust (the "Acquisition").

In
connection with the Acquisition, Greylock assumed all of Legacy ECA's obligations under the Amended and Restated Trust Agreement among the Trust, Legacy ECA and the Trustee, and other
instruments to which Legacy ECA and the Trustee are parties, including (1) the Administrative Services Agreement by and among Legacy ECA, the Trust and the Trustee dated July 7, 2010,
and (2) a letter agreement between Legacy ECA and the Trustee regarding certain loans to be made by Legacy ECA to the Trust as necessary to enable the Trust to pay its liabilities as they
become due (the "Letter Agreement"). In addition, Legacy ECA, Greylock, and the Trustee entered into a Reaffirmation and Amendment of Mortgage, Assignment of Leases, Security Agreement, Fixture Filing
and Financing Statement (the "Reaffirmation Agreement"), pursuant to which, among other things, Greylock (1) reaffirmed the liens and the security interest granted pursuant to the existing
mortgage securing the interests in the subject properties, as well as the mortgage and the obligations of Legacy ECA under the mortgage, and (2) assumed the obligations of Legacy ECA under the
Letter Agreement.

The
Trust makes copies of its reports under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), available at www.businesswire.com/cnn/ect.htm. The Trust's filings under
the Exchange Act are also available electronically from the website maintained by the SEC at http://www.sec.gov. The Trust will also provide electronic and paper copies of its filings free of charge
upon request to the Trustee.

General

The Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Royalty Interests (described below), to
distribute to the Trust unitholders cash that
the Trust receives in respect of the Royalty Interests after the 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. The Trust is treated as a partnership for federal and state income tax purposes.

Initially,
the Trust owned royalty interests in the 14 Producing Wells described in the Prospectus (the "Producing Wells") and royalty interests in 52 horizontal natural gas development
wells to be drilled to the Marcellus Shale formation (the "PUD Wells") within the AMI, in which Legacy ECA held approximately 9,300 acres, of which it owned substantially all of the working interests,
in Greene County, Pennsylvania. The AMI consisted of the Marcellus Shale formation in approximately 121 square miles in Greene County, Pennsylvania.

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Legacy
ECA completed its drilling obligation to the Trust under the Development Agreement as of November 30, 2011, approximately 2.3 years in advance of the required
completion date of March 31, 2014. Consequently, no additional wells have been or will be drilled for the Trust. As of December 31, 2017 the Trust owns Royalty Interests in the 14
Producing Wells and the 40 development wells (52.06 Equivalent PUD Wells) that are now completed and in production. The 14 Producing Wells and the 40 development wells (52.06 Equivalent PUD
Wells) are sometimes herein called the "Trust Wells".

The
royalty interests were conveyed from Legacy 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 Legacy ECA's interest in the Producing Wells for a period of 20 years commencing on
April 1, 2010 and 45% thereafter. The royalty interest in the PUD Wells (the "PUD Royalty Interest" and together with the PDP Royalty Interest, the "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 Legacy ECA's interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter. As used herein, the term "Producing Wells" means the 14
Producing Wells as defined above, and does not include the 40 PUD Wells, although they also have been completed and are producing.

Legacy
ECA was obligated to drill all of the PUD Wells no later than March 31, 2014. As of November 30, 2011, Legacy 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 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 Legacy ECA for such post-production costs on the related Greene County
Gathering System (the "Post-Production Services Fee") were limited to $0.52 per MMBtu gathered until Legacy ECA fulfilled its drilling obligation in 2011; since then Legacy ECA was, and after the
Acquisition Greylock is, 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) Legacy ECA's net revenue interest in the well. Legacy 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 are calculated on the basis that the underlying PUD Wells are burdened only by interests that in
total would not exceed 12.5% of the revenues from such properties, regardless of whether the royalty interest owners are actually entitled to a greater percentage of revenues from such properties. As
an example, assuming Legacy ECA owns a 100% working interest in a PUD Well, the applicable net revenue interest is calculated by multiplying Legacy 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 Legacy ECA's working interest in a PUD Well is less than 100%, the Trust's share of proceeds would be proportionately reduced.

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As
described under "Duration of the Trust; Sale of Royalty Interests" below, the Trust is required to dissolve if the gross proceeds received by the Trust attributable to
the Royalty Interests over any four consecutive quarters are less than $1.5 million. Gross proceeds over the four consecutive quarters ended December 31, 2017 were $6.9 million.

Historical Target Distributions

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 the 60th day following the completion of each quarter. Unless it is sooner liquidated, the Trust will
liquidate on or about March 31, 2030.

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



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. The amount of the quarterly distributions fluctuates 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 ("ECI") should be made at the
highest marginal rate. Under IRC 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. The recently enacted Tax Cuts and Jobs Act treats a non-U.S. holder's gain on the sale of Trust units as ECI to the extent such holder would have had ECI if the Trust had
sold all of its assets at fair market value on the date of the exchange. The new legislation also requires the transferee of units to withhold 10% of the amount realized on the sale of exchange of
units (generally, the purchase price) unless the transferor certifies that it is not a nonresident alien individual or foreign corporation.

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 the 60th day following the completion of each quarter. Unless sooner liquidated, as discussed in detail below under the caption "The Trustee
may, under certain circumstances, sell the Royalty Interests and dissolve the Trust. Unless sooner terminated, the Trust will begin to terminate following the end of the 20 year period in which
the Trust owns the Term Royalty Interests" in Item 1A. Risk Factors, the Trust will liquidate on or about March 31, 2030 (the "Termination Date"). At the Termination Date, 50% of each of
the PDP Royalty Interest and the PUD Royalty Interest will revert automatically to Greylock. 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

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soon
after the Termination Date. Greylock will have a right of first refusal to purchase the remaining 50% of the Royalty Interests at the Termination Date. Because payments to the Trust will be
generated by depleting assets and the Trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent a return of the
original investment in the Trust units.

The
Trustee can authorize the Trust to borrow money to pay Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow
from the Trustee as
a lender provided the terms of the loan are fair to the Trust unitholders, although the Trustee does not intend to make any such loans. The Trustee may also deposit funds awaiting distribution in an
account with itself, if the interest paid to the Trust at least equals amounts paid by the Trustee on similar deposits, and make other short term investments with the funds distributed to the Trust.
The Trustee may also hold funds awaiting distribution in a non interest bearing account.

The
Trust is responsible for paying all legal, accounting, tax advisory, engineering, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction
of the Trustee. The Trust is also responsible for paying other expenses, including the expenses of tax return and Schedule K-1 preparation and distribution, and expenses incurred as a result of
being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, independent auditor fees and registrar and transfer agent fees.

The Administrative Services Agreement

The Trust is party to an Administrative Services Agreement ("ASA") with Greylock, which assumed Legacy ECA's obligations under the ASA
subsequent to the Acquisition. The ASA obligates the Trust to pay Greylock an administrative services fee for accounting, bookkeeping and informational services to be performed by Greylock 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, Greylock and the Trustee each may terminate the ASA
at any time following delivery of notice no less than 90 days prior to the date of termination.

The Development Agreement

In connection with the formation of the Trust, the Trust and Legacy ECA entered into a Development Agreement that obligated Legacy ECA to drill
all of the PUD Wells by March 31, 2014. Legacy ECA granted to the Trust a lien on Legacy ECA's interest in the Marcellus Shale formation in the AMI (except the Producing Wells and any other
wells which were already producing and not subject to the Royalty Interests) to secure the estimated amount of the drilling costs for the Trust's interests in the PUD Wells (the "Drilling Support
Lien"). The original maximum amount of the Drilling Support Lien was $91 million. As Legacy ECA fulfilled its drilling obligation over time, the total dollar amount recovered was
proportionately reduced and the completed PUD Wells were released from the lien. As of November 30, 2011, the Drilling Support Lien had been fully released.

For
purposes of Legacy ECA's drilling obligation, and subject to the following paragraph, Legacy ECA was credited with a full development well drilled if its working interest in the
development well drilled was 100%. Where Legacy ECA's working interest in a development well drilled was less than 100%, Legacy ECA was credited with a portion of a development well in the proportion
that its working interest in the development well bears to 100%. For example, if Legacy ECA's working interest in a development well drilled by Legacy ECA in connection with fulfilling its drilling
obligation to the Trust was 50%, Legacy ECA was credited with one-half of a development well for purposes of satisfying its drilling obligation in the period the development well was drilled.

Wells
drilled horizontally with a horizontal lateral distance (measured from the midpoint of the curve to the end of the lateral) of less than 2,500 feet counted as a Fractional well in
proportion to

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total
lateral length divided by 2,500 feet. Wells with a horizontal lateral distance of greater than 2,500 feet (subject to a maximum of 3,500 feet) counted as one well plus a Fractional well
equal to the length drilled in excess of 2,500 (up to 3,500 feet) feet divided by 2,500 feet.

In
accordance with these provisions of the Development Agreement, Legacy ECA drilled 40 development wells (52.06 Equivalent PUD Wells) to fulfill its obligation to drill the 52 PUD Wells
as required.

Legacy
ECA was obligated to bear all of the costs of drilling and completing the PUD Wells. Legacy ECA was required to complete and equip each development well that reasonably appeared
to be capable of producing gas in quantities sufficient to pay completion, equipping and operating costs. Legacy ECA drilled, completed and equipped each of the development wells.

Legacy
ECA and, following the Acquisition, Greylock agreed not to drill and complete, and not to permit any other person within its control to drill and complete, any well on the lease
acreage that would have a perforated segment within 500 feet of any perforated interval of a PUD Well or Producing Well in the Marcellus Shale formation.

Marketing and Post-Production Services

Pursuant to the terms of the conveyances creating the Royalty Interests, Greylock has the responsibility to market, or cause to be marketed, the
natural gas production related to the Underlying Properties. The terms of the conveyances creating the Royalty Interests do not permit Greylock to charge any marketing fee when determining the
proceeds upon which the royalty payments are calculated. As a result, the proceeds to the Trust from the sales of natural gas production from the Underlying Properties are determined based on the same
price (net of post-production costs) that Greylock receives for natural gas production attributable to Greylock's retained interest.

Greylock
markets the majority of its operated production and markets all of the natural gas produced from the Underlying Properties. Greylock enters into gas sales arrangements with
large aggregators of supply, and these arrangements may be on a month-to-month basis or may be for a term of up to one year or longer. The natural gas is sold at a market price and any applicable
post-production costs are deducted.

All
of the production from the Producing Wells and the PUD Wells is currently gathered by Greylock on the Greene County Gathering System that it operates and owns an interest in. The
Trust paid the initial Post-Production Services Fee of $0.52 per MMBtu for use of this system, including Greylock's costs to gather, compress, transport, process, treat, dehydrate and market the gas.
This fee was fixed until Legacy ECA's drilling obligation was satisfied in 2011; since then, Legacy ECA was, and after the Acquisition Greylock is, permitted to increase this fee to the extent
necessary to recover certain capital expenditures on the Greene County Gathering System made after the completion of the drilling period, provided the resulting charge does not exceed the prevailing
charges in the area for similar services. This fee does not include the cost of fuel used in the compression process or equivalent electricity charges when electric compressors are used, firm
transportation charges on interstate gas pipelines, or other third-party charges. The Trust's cash available for distribution is reduced by Greylock's deductions for these post-production services.

Greylock
may enter into arrangements with third parties to provide gathering, transportation, processing and other reasonable post-production services, including transportation on
downstream interstate pipelines. Such additional post-production costs will be expressed as either (1) a cost per MMBtu or Mcf or (2) a percentage of the gross production from a well. To
the extent that post-production costs are expressed as a cost per MMBtu or Mcf, such costs may be deducted by the purchaser of the natural gas prior to payment being made to Greylock for such
production. At other times, Greylock will make payments directly to the third parties providing such post-production

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services.
In either instance, the Trust's cash available for distribution will be reduced by the costs paid by Greylock for such post-production services provided by third parties. If the
post-production costs are expressed as a percentage of the gross production from a well, then the volume of production from that well actually available for sale is less than the applicable percentage
charged, and as a result the reserves associated with that well that are attributable to the Royalty Interests are reduced accordingly.

The
post-production costs for the Trust's natural gas produced and sold averaged $0.69 per MMBtu for the years ended December 31, 2017 and 2016, respectively. Such costs may
increase or decrease in the future. The post-production costs attributable to third party arrangements may be costs established by arms-length negotiations or pursuant to a state or federal regulatory
proceeding. Greylock is permitted to deduct from the proceeds payable to the Trust other post-production costs necessary to make the natural gas from the Underlying Properties marketable, so long as
such costs do not materially exceed the charges prevailing in the area for similar services.

Greylock
assumed Legacy ECA's obligations under an agreement with Columbia Gas Transmission, LLC ("Columbia") to provide firm transportation downstream of Greylock's Greene County
Gathering System for 50,000 MMBtu per day. This firm transportation arrangement, which terminates July 31, 2021, has been in effect since August 1, 2011 and is at Columbia's filed tariff
rate, which is currently $0.1878 per MMBtu at one hundred percent load factor. This firm transportation is an additional post-production cost and the Trust bears its proportionate share of such costs.

Greylock
may enter into similar gas supply arrangements and post-production service arrangements for the natural gas to be produced from the Underlying Properties. Any new gas supply
arrangements or those entered into for providing post-production services, will be utilized in determining the proceeds for the Underlying Properties.

Competition and Markets

The natural gas industry is highly competitive. Greylock competes with major oil and gas companies and independent oil and gas companies for oil
and gas leases, equipment, personnel and markets for the sale of natural gas. Many of these competitors are financially stronger than Greylock, but even financially troubled competitors can affect the
market because they may need to sell natural gas regardless of price to attempt to maintain cash flow. The Trust is subject to the same competitive conditions as Greylock and other companies in the
natural gas industry.

Natural
gas competes with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the
availability or price of natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of
energy may affect the demand for natural gas.

Future
prices for natural gas will directly affect Trust distributions, estimates of reserves attributable to the Trust's interests, and estimated and actual future net revenues to the
Trust. In view of the many uncertainties that affect the supply and demand for natural gas, neither the Trust nor Greylock can make reliable predictions of future gas supply or demand, future gas
prices or the effect of future gas prices on the Trust.

Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale
of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC.
Federal and state regulations govern the price and terms for access to

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natural
gas pipeline transportation. The FERC's regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although
natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. Neither Greylock nor the Trust can predict whether new
legislation to regulate natural gas prices might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals
might have on the operations of the Underlying Properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

Environmental Matters and Regulation

The operations of the properties composing the Underlying Properties are subject to stringent and complex federal, state and local laws and
regulations governing environmental protection, the discharge, emission or release of materials into the environment and employee health and safety. These laws and regulations may, among other
things:



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

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

Environmental, Health and Safety Regulation.The exploration, development and production operations of Greylock are subject to
stringent and
comprehensive federal, state and local laws and regulations governing the discharge, emission or release of materials into the environment or otherwise relating to environmental protection or human
health and safety. These laws and regulations may, among other things, require the acquisition of permits to conduct construction, drilling, water withdrawal and waste disposal operations; govern the
amounts and types of substances that may be disposed or released into the environment; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or
areas containing endangered or threatened species or their habitats; require investigatory and remedial actions to mitigate pollution conditions arising from Greylock's operations or attributable to
former operations; and impose obligations to reclaim and abandon well sites, impoundments and pits. Failure to comply with these laws and regulations may

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result
in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of Greylock's operations in affected
areas.

Changes
in environmental regulation may place more restrictions and limitations on activities that may affect the environment, and thus, any future changes in environmental laws and
regulations or re-interpretation of enforcement policies that result in more stringent or costly construction, drilling, water withdrawal, waste handling, storage, transport, disposal, or remediation
requirements could have a material adverse effect on Greylock's capital expenditures, results of operations and financial position. Greylock may be unable to pass on increased compliance costs to its
customers. Moreover, accidental loss of well control, or releases or spills may occur in the course of Greylock's operations, and Greylock could incur significant costs and liabilities as a result of
such incidents, including any third party claims for damage to property and natural resources or personal injury. Although Greylock believes that it is in substantial compliance with existing
environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on Greylock's capital expenditures, results of operations or
financial position, Greylock might not be able to maintain such compliance in the future.

The
following is a summary of significant existing environmental, health and safety laws and regulations to which Greylock's business operations are subject and for which compliance may
have a material adverse impact on Greylock's capital expenditures, results of operations or financial position.

Hazardous Substances and Wastes.The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, ("CERCLA"),
also known as the
Superfund law and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be jointly and severally
responsible for the release of a "hazardous substance" into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that
disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be liable for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in
response to threats to the public health or the environment and then to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. Greylock handles materials
in the course of Greylock's operations that may be regulated as hazardous substances.

Greylock
also generates solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable state statutes.
RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of its operations, Greylock generates petroleum hydrocarbon
wastes and ordinary industrial wastes that may be classified as hazardous wastes under CERCLA and comparable state laws. On December 28, 2016, the EPA entered into a settlement with
environmental groups wherein it agreed to decide by March 2019 whether to revise the Agency's current determination exempting oil and gas wastes from regulation as RCRA hazardous wastes.

Greylock
currently owns or leases, and in the past may have owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although
Greylock may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released at or from the properties
owned or leased by Greylock or at or from the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated
by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under Greylock's control.

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These
properties and wastes disposed thereon may give rise to liability under CERCLA, RCRA and analogous state laws. Under these laws, Greylock could be required to investigate, remove or remediate
previously disposed wastes, to clean up contaminated property and to perform response actions to prevent future contamination.

Air Emissions.The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from
many sources and
also impose various monitoring and reporting requirements. These laws and regulations may require Greylock to obtain pre-approval for the construction or modification of certain projects or facilities
expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions.
Obtaining permits has the potential to delay the development of Greylock's properties. While Greylock may be required to incur certain capital expenditures during the next few years for air pollution
control equipment or other air emissions-related issues, Greylock does not believe that such requirements have a material adverse effect on its operations.

In
December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (collectively, "GHGs") present an endangerment to public health and
the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. These findings allow the EPA to adopt and
implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that could trigger permit review for
GHG emissions from certain stationary sources. Those regulations were challenged in federal court and the Supreme Court has upheld the EPA's authority to regulate GHG emissions from stationary
sources, concluding sources that trigger air permitting requirements based on their traditional criteria pollutant emissions must include a limit for greenhouse gases in their permit. The EPA has also
issued regulations that require the establishment and reporting of an inventory of GHG emissions from specified stationary sources, including certain onshore oil and natural gas exploration,
development and production facilities. On October 23, 2015, the EPA finalized its "Clean Power Plan" regulations under Section 111(d) of the Clean Air Act to limit GHG emissions from
existing power plants. Several states, trade groups and companies have challenged the legality of EPA's 111(d) rule for existing power plants in federal court. On February 9, 2016, the Supreme
Court granted an emergency stay preventing EPA from implementing the Clean Power Plan until the D.C. Circuit issues a decision on the legality of the rule and disposition of a writ of certiorari, to
the extent such a writ is sought. On October 10, 2017, following a review directed by President Trump's March 2017 Energy Independence Executive Order, the EPA proposed to repeal the Clean
Power Plan regulations. The public comment period on the proposed repeal has been extended to April 26, 2018.

In
June 2016, the EPA adopted New Source Performance Standards ("NSPS") under Section 111 of the federal Clean Air Act that require control of the GHG methane from new sources in
the oil and gas industry, building on a 2012 rule aimed at controlling ozone-forming pollutants from the industry. The EPA also issued a series of Information Collection Requests to industry seeking
assistance in developing a program for regulating methane emissions from existing oil and gas sources. The EPA withdrew the Information Collection Requests in 2017, however, and announced that it
would convene a proceeding to reconsider certain parts of the June 2016 oil and gas NSPS. The EPA has also moved forward with a proposed rule that seeks to delay the compliance deadline for certain
requirements of the June 2016 oil and gas NSPS. The ultimate fate of the June 2016 oil and gas NSPS is unclear.

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

The
adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, Greylock's equipment and operations could require Greylock to
incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas it produces. Legislation or regulations that may be adopted to address
climate change could also affect the markets for Greylock's products by making its products more or less desirable than competing sources of energy. To the extent that its products are competing with
higher GHG-emitting energy sources, Greylock's products may become more desirable in the market with more stringent limitations on GHG emissions. To the extent that its products are competing with
lower GHG-emitting energy, Greylock's products may become less desirable in the market with more stringent limitations on
greenhouse gas emissions. Greylock cannot predict with any certainty at this time how these possibilities may affect its operations.

Finally,
some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as
increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on Greylock's assets and operations.

Water Discharges.The Federal Water Pollution Control Act, as amended ("Clean Water Act"), and analogous state laws impose restrictions
and strict
controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or
waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by EPA or the analogous state agency. The term
"waters of the United States" has been broadly defined to include certain inland water bodies, including certain wetlands and intermittent streams. In May 2015, the EPA finalized a new definition of
"waters of the United States" that broadens the scope of regulated waters. Several states, trade groups and companies have challenged the legality of EPA's new definition for "waters of the United
States" in various federal courts and in October 2015, the Sixth Circuit Court of Appeals issued a nationwide stay of the rule. In February 2017, President Trump signed an Executive Order announcing
that the Administration would review the May 2015 rule. EPA and the Department of the Army proposed to rescind the May 2015 rule in July 2017. While that proposal has not been finalized, EPA and the
Department of the Army have also, in November 2017, proposed to add an applicability date to the May 2015 rule that would delay applicability of the rule by at least two years. While there is
significant uncertainty regarding the "waters of the United States" rule, Greylock believes that the rule, even in its May 2015 form, would not have a material adverse effect on the cash distributions
to the Trust unitholders.

The
Pennsylvania Department of Environmental Protection has adopted a new permitting policy concerning surface water discharges from wastewater treatment facilities handling flowback
fluids and produced waters from oil and gas well sites that could result in increased requirements for treatment of these fluids and limitations on their discharge to receiving waters. In April 2015,
EPA proposed technology-based pretreatment standards under the Clean Water Act for discharges of effluent from unconventional oil and gas extraction facilities to publicly owned treatment works
("POTWs"). In June 2016, EPA issued a final rule implementing wastewater pretreatment standards that prohibits onshore unconventional oil and gas extraction facilities from sending wastewater directly
to POTWs.

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Unconventional
oil and gas extraction facilities can send wastewater to a private wastewater treatment facility that can either discharge treated wastewater or send it to a POTW. EPA is conducting a
related
study of treatment of oil and gas extraction wastewater at private wastewater treatment facilities. If Greylock is unable to remove and dispose of water at a reasonable cost and within applicable
environmental rules, Greylock's ability to produce gas commercially and in commercial quantities from the Underlying Properties could be impaired.

Spill
prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable
waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws, including in Pennsylvania, require individual permits or coverage
under general permits for discharges of storm water runoff from certain types of facilities.

Endangered Species Act.The federal Endangered Species Act, as amended ("ESA"), restricts activities that may affect endangered and
threatened
species or their habitats. As a result of a settlement reached in 2011, the United States Fish and Wildlife Service is required to make a determination on whether to list numerous species as
endangered or threatened under the ESA over the next several years. The designation of previously unidentified endangered or threatened species could cause Greylock to incur additional costs or become
subject to operating restrictions or bans in the affected areas.

Employee Health and Safety.The operations of Greylock are subject to a number of federal and state laws and regulations, including the
federal
Occupational Safety and Health Act, as amended ("OSHA"), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication
standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained
concerning hazardous materials used or produced in Greylock's operations and that this information be provided to employees, state and local government authorities and citizens.

State Regulation.Pennsylvania regulates the drilling for, and the production, gathering, storage, transport and sale of natural gas,
including
imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells, production rates and the prevention of waste of natural gas resources.
Any and all chemicals or other materials involved in the process must be disclosed and approved per statute. PADEP continues to implement new regulations specifically applicable to the development of
unconventional gas wells. The Pennsylvania Public Utility Commission is charged with enforcement of the gas well impact fees, penalties for nonpayment, and additional requirements resulting from the
adoption of the amendments. Proposed regulations and new requirements resulting from the amendments could require Greylock to incur increased operating costs. Realized prices are not currently subject
to state regulation or other similar direct economic regulation, but they could become subject to such regulation in the future. The effect of these regulations may be
to limit the amounts of natural gas that may be produced from Greylock's and to limit the number of wells or locations Greylock can drill.

Greylock
believes that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. On
December 24, 2015, Legacy ECA received a Notice of Violation ("NOV") from PADEP relating to Legacy ECA's operation of various water impoundments constructed on numerous well pad sites situated
in Greene and Clearfield counties covering some of the Underlying Properties. Prior to the Acquisition, Legacy ECA reached a Consent Order and Agreement ("COA") with PADEP under which Legacy ECA
agreed to pay a $1.7 million Civil Penalty Settlement to PADEP and to remediate the environmental impacts as described in the COA. However, pursuant to the conveyances these expenses incurred
by Legacy ECA related to the NOV are not deductible from the proceeds due to the Trust and therefore did not affect

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cash
distributions to Trust unitholders. As such, there were no material capital expenditures for remediation or pollution control activities for the years ended December 31, 2017 and 2016,
with respect to the Underlying Properties.

Description of the Trust Units

Each Trust unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis.
The Trust has 17,605,000 common units outstanding.

Distributions and Income Computations

Cash distributions to Trust unitholders are made from available funds of the Trust for each calendar quarter. Production payments due to the
Trust with respect to any calendar quarter are accrued based on estimated production volumes attributable to the Trust properties during such quarter (as measured at Greylock metering systems) and
market prices for such volumes. Greylock makes a payment to the Trust equal to such accrued amounts within 30 days of the end of each such
calendar quarter. After receipt of such payment, the Trustee determines for such calendar quarter the amount of funds available for distribution to the Trust unitholders. Available funds are the
excess cash, if any, received by the Trust over the Trust's expenses for that quarter, reduced by any net increases to reserves. Any difference between the payment made by Greylock to the Trust with
respect to a calendar quarter and the actual cash production payments relative to the Trust properties received by Greylock will be netted to or against future payments by Greylock to the Trust.

The
amount of available funds for distribution each quarter is payable to the Trust unitholders of record on or about the 45th day following the end of such calendar quarter or
such later date as the Trustee determines is required to comply with legal or stock exchange requirements. The Trust distributes available cash on or about the 60th day (or the next succeeding
business day following such day if such day is not a business day) following such calendar quarter to each person who was a Trust unitholder of record on the quarterly record date.

Unless
otherwise advised by counsel or the IRS, the Trustee will treat the income and expenses of the Trust for each month as belonging to the Trust unitholders of record on the first
business day of the month.

Transfer of Trust Units

Trust unitholders may transfer their Trust units in accordance with the Trust Agreement. The Trustee does not require either the transferor or
transferee to pay a service charge for any transfer of a Trust unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of
any Trust unit as shown by its records as the owner of the Trust unit. The Trustee will not be considered to know about any claim or demand on a Trust unit by any party except the record owner. A
person who acquires a Trust unit after any quarterly record date will not be entitled to any distribution relating to that quarterly record date. Delaware law governs all matters affecting the title,
ownership or transfer of Trust units.

Periodic Reports

The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to each Trust
unitholder a Schedule K-1 to enable unitholders to correctly report their respective share of the income and deductions of the Trust. The Trustee also causes to be prepared and filed reports
required to be filed under the Exchange Act and by the rules of the New York Stock Exchange.

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Each
Trust unitholder and such unitholder's representatives may examine, for any proper purpose, during reasonable business hours, the records of the Trust.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act, Trust unitholders will be entitled to the same limitation of personal liability extended to stockholders
of private corporations for profit under the General Corporation Law of the State of Delaware. Nevertheless, courts in jurisdictions outside of Delaware may not give effect to such limitation.

Voting Rights of Trust Unitholders

The Trustee or Trust unitholders owning at least 10% of the outstanding Trust units may call meetings of Trust unitholders. The Trust will be
responsible for all costs associated with calling a meeting of Trust unitholders unless such meeting is called by the Trust unitholders, in which case the Trust unitholders will be responsible for all
costs associated with calling such meeting of Trust unitholders. Meetings must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send written
notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust
unitholders representing a majority of Trust units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust unit owned.

Unless
otherwise required by the Trust Agreement, a matter may be approved or disapproved by the vote of a majority of the Trust units held by the Trust unitholders at a meeting where
there is a quorum. This is true, even if a majority of the total outstanding Trust units did not approve it. The affirmative vote of the holders of a majority of the outstanding Trust units is
required to:



except
that if any of the matters listed above (except removal of the Trustee or the Delaware Trustee) would result in a materially disproportionate benefit to Greylock or its affiliates compared to
other owners of common units, the affirmative vote of the holders of a majority of common units and a majority of Trust units is required.

In
addition, certain amendments to the Trust Agreement may be made by the Trustee without approval of the Trust unitholders. The Trustee must consent before all or any part of the Trust
assets can be sold except in connection with the dissolution of the Trust or limited sales directed by Greylock in conjunction with its sale of Underlying Properties.

Description of the Trust Agreement

The Trust was created under Delaware law to acquire and hold the Royalty Interests for the benefit of the Trust unitholders pursuant to an
agreement between Legacy ECA, the Trustee and the Delaware Trustee. Greylock has assumed Legacy ECA's obligations under the Trust Agreement as

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described
under "Introduction" above. The Royalty Interests are passive in nature and neither the Trust nor the Trustee has any control over or responsibility for costs relating to the
operation of the Underlying Properties. Neither Greylock nor other operators of the Underlying Properties have any contractual commitments to the Trust to provide additional funding or to conduct
further drilling on or to maintain their ownership interest in any of these properties.

The
Trust Agreement provides that the Trust's business activities are limited to owning the Royalty Interests and any activity reasonably related to such ownership, including activities
required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not permitted to acquire other oil and gas properties or royalty interests. The Trust
is not able to issue any additional Trust units.

Duties and Powers of the Trustee

The duties of the Trustee are specified in the Trust Agreement and by the laws of the State of Delaware, except as modified by the Trust
Agreement. The Trustee's principal duties consist of:



If
a Trust liability is contingent or uncertain in amount or not yet currently due and payable, the Trustee may create a cash reserve to pay for the liability. If the Trustee determines
that the cash on hand and the cash to be received are insufficient to cover the Trust's liability, the Trust may borrow funds required to pay the liabilities. The Trust may borrow the funds from any
person, including the Trustee or its affiliates. The terms of such indebtedness, if funds were loaned by the entity serving as Trustee or Delaware Trustee, would be similar to the terms which such
entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such
indebtedness as if it were not then serving as Trustee or Delaware Trustee. If the Trustee borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid.

Responsibility and Liability of the Trustee

The duties and liabilities of the Trustee are set forth in the Trust Agreement. The Trust Agreement provides that (i) the Trustee shall
not have any duties or liabilities, including fiduciary duties, except as expressly set forth in the Trust Agreement, and (ii) the duties and liabilities of the
Trustee as set forth in the Trust Agreement replace any other duties and liabilities, including fiduciary duties, to which the Trustee might otherwise be subject.

The
Trustee does not make business decisions affecting the assets of the Trust, and the Trustee's functions under the Trust Agreement are ministerial in nature. In discharging its duty
to Trust unitholders, the Trustee may act in its discretion and will be liable to the Trust unitholders only for fraud, gross negligence or acts or omissions constituting bad faith. The Trustee will
not be liable for any act or omission of its agents or employees unless the Trustee acted with fraud, in bad faith or with gross negligence in their selection and retention. The Trustee will be
indemnified individually or as the Trustee for any liability or cost that it incurs in the administration of the Trust, except in cases of fraud,

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gross
negligence or bad faith. The Trustee has a lien on the assets of the Trust as security for this indemnification and its compensation as Trustee.

Assets of the Trust

The assets of the Trust consist of the Royalty Interests, the Administrative Services Agreement, and any cash and temporary investments being
held for the payment of expenses and liabilities and for distribution to the Trust unitholders.

Liabilities of the Trust

Because the Trust does not conduct an active business and the Trustee has little power to incur obligations, it is expected that the Trust will
incur liabilities only for routine administrative expenses, such as the Trustee's fees and accounting, engineering, legal, tax advisory and other professional fees.

Fees and Expenses

The Trust is responsible for paying all legal, accounting, tax advisory, engineering, printing and other administrative and out-of-pocket
expenses incurred by or at the direction of the Trustee or the Delaware Trustee. The Trust is also responsible for paying expenses of tax returns and Schedule K-1 preparation and distribution,
as well as expenses incurred as a result of its being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, independent auditor fees and registrar and
transfer agent fees.

Duration of the Trust; Sale of Royalty Interests

The Trust is expected to remain in existence until the Termination Date, which is March 31, 2030. The Trust will dissolve prior to the
Termination Date if:



The
Trustee would then sell all of the Trust's assets, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders.

Greylock's Right of First Refusal

Greylock has a right of first refusal to purchase the Perpetual Royalty Interests upon termination of the Trust. This right of first refusal
provides that the Trustee will use commercially reasonable efforts to retain a third-party advisor to market the Perpetual Royalty Interests within 30 business days of the termination of the Trust. If
the Trustee receives a bid from a proposed purchaser other than Greylock, prior to selling all or part of the Perpetual Royalty Interests, it will be required to give notice (the "Offer Notice") to
Greylock, identifying the proposed purchaser and setting forth the proposed sale price, payment terms and other material terms of the proposed sale. Greylock would then have 30 days from
receipt of the Offer Notice to elect, by notice to the Trustee, to purchase the subject properties offered for sale on the terms and conditions set forth in the Offer Notice. If Greylock makes such
election, the proposed purchaser would be entitled to receive reimbursement of its reasonable and documented expenses incurred in connection with its review and analysis of the subject properties and
bid preparation. Greylock and the Trust would share equally the cost of reimbursement to the proposed purchaser.

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If
Greylock does not give notice within the 30-day period following the Offer Notice, the Trust may sell such properties to the identified purchaser on terms and conditions that are
substantially the same as those previously set forth in such Offer Notice.

If,
after a reasonable marketing period, no bid is received on any or all of the Perpetual Royalty Interests from any party other than Greylock, then, as a condition to the sale,
Greylock shall obtain, at the Trust's expense, and deliver to the Trustee, a fairness opinion from a nationally-recognized valuation firm with expertise in fairness opinions stating that the proposed
sale price to be paid by Greylock to the Trust for the properties is fair to the Trust.

Federal Income Tax Considerations

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

Miscellaneous

The Trustee may consult with counsel, accountants, tax advisors, geologists and engineers and other parties the Trustee believes to be qualified
as experts on the matters for which advice is sought. The Trustee will be protected for any action it takes in good faith reliance upon the opinion of the expert.

The
Delaware Trustee and the Trustee may resign at any time or be removed with or without cause at any time by a vote of not less than a majority of the outstanding Trust units. Any
successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20 million, in the case of the Delaware
Trustee, and $100 million, in the case of the Trustee.

Item 1A.Risk Factors

Natural gas prices fluctuate due to a number of factors that are beyond the control of the Trust and
Greylock, and lower prices would reduce proceeds to the Trust and cash distributions to unitholders.

The Trust's reserves and quarterly cash distributions are highly dependent upon the prices realized from the sale of natural gas. Natural gas
prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and Greylock. These factors include, among
others:



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Lower
natural gas prices will reduce proceeds to which the Trust is entitled and may ultimately reduce the amount of natural gas that is economic to produce from the Underlying
Properties. As a result, the operator of any of the Underlying Properties could determine during periods of low natural gas prices to shut in or curtail production from wells on the Underlying
Properties. In addition, the operator of the Underlying Properties could determine during periods of low natural gas prices to plug and
abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, Greylock may abandon any well or property if it
reasonably believes that the well or property can no longer produce natural gas in commercially economic quantities. This could result in termination of the portion of the royalty interest relating to
the abandoned well or property, and Greylock would have no obligation to drill a replacement well. In making such decisions, Greylock is required under the applicable conveyance to act as a reasonably
prudent operator in the AMI under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as burdens
affecting such property. The volatility of natural gas prices also reduces the accuracy of estimates of future cash distributions to Trust unitholders.

Actual reserves and future production may be less than current estimates, which could reduce cash
distributions by the Trust and the value of the Trust units.

The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the
accuracy of the reserves estimated to be attributable to the Trust's Royalty Interests. The Trust's reserve quantities and revenues are based on estimates of reserve quantities and revenues for the
Underlying Properties. See "The underlying propertiesNatural gas reserves" in the Prospectus for a discussion of the method of allocating Proved reserves to the Trust. It is not possible
to measure underground accumulations of natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could
vary negatively and in material amounts from estimates and those variations could be material. Petroleum engineers are required to make subjective estimates of underground accumulations of natural gas
based on factors and assumptions that include:



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Changes
in these assumptions or actual production costs incurred and results of actual development and production costs could materially decrease reserve estimates.

Further,
the reserve report estimating the Trust's proved reserves, future production and income attributable to the Trust's Royalty Interests as of December 31, 2017 was
prepared, in accordance with applicable regulations, using a weighted benchmark price adjusted for differentials resulting in an average natural gas price of $2.63 per Mcf during 2017, as described in
Appendix A to this report. At the date of this report, the weighted benchmark natural gas price, adjusted for differentials, for production in which the Trust has an interest is below $2.63. A
reserve report prepared using the current lower value would result in lower proved reserves, future production and income attributable to the Trust's Royalty Interests.

The generation of proceeds for distribution by the Trust depends in part on gathering, transportation and
processing facilities owned by Greylock and others. Any limitation in the availability of those facilities could interfere with sales of natural gas production from the Underlying Properties.

The amount of natural gas that may be produced and sold from any well to which the Underlying Properties relate is subject to curtailment in
certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered gas to meet quality specifications of gathering
lines or downstream transporters, excessive line pressure which prevents delivery of gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such
systems. The curtailments may vary from a few days to several months. In many cases, Greylock is provided limited notice, if any, as to when production will be curtailed and the duration of such
curtailments. If Greylock is forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced
due to the reduction of proceeds from the sale of production.

The generation of proceeds for distribution by the Trust depends in part on the ability of Greylock and/or
its customers to obtain service on transportation facilities owned by third party pipelines. Any limitation in the availability of those facilities and/or any increase in the cost of service on those
facilities could interfere with sales of natural gas production from the Underlying Properties.

Natural gas that is gathered on the Greene County Gathering System, including natural gas produced from the Underlying Properties, is currently
shipped on two interstate natural gas transportation pipelines. Greylock or its purchasers have contracted with those pipelines for firm or interruptible transportation service. The rates for service
on the transportation pipelines are regulated by the FERC and are subject to increase if the pipeline demonstrates that the existing rates are unjust and unreasonable.

Greylock
has an agreement with Columbia to provide firm transportation downstream of Greylock's Greene County Gathering System for 50,000 MMBtu per day. This firm transportation
arrangement, which terminates July 31, 2021, has been in effect since August 1, 2011 and is at Columbia's filed tariff rate, which is currently $0.1878 per MMBtu at a one hundred percent
load factor. This firm transportation is an additional post-production cost, and the Trust bears its proportionate share of such costs.

In
the future, Greylock may seek to obtain additional firm transportation capacity, but such capacity may not be available. In addition, to the extent Greylock's customers or Greylock
became dependent on interruptible service, and to the extent that either pipeline receives requests for service that exceed the capacity of the pipeline, the pipeline will honor requests by its firm
customers first, and will then allocate remaining capacity, if any, to interruptible shippers. As a result, Greylock or its customers may be unable to obtain all or a part of any requested
interruptible capacity service on the transportation pipelines. Any inability of Greylock or its customers to procure sufficient capacity to

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transport
the natural gas gathered on the Greene County Gathering System will decrease and/or delay the receipt of any proceeds that may be associated with natural gas production from wells on the
Underlying Properties. In addition, any increase in transportation rates paid by Greylock for production attributable to the Trust's interests will decrease the proceeds received by the Trust.

Due to the Trust's lack of industry and geographic diversification, adverse developments in the Trust's
existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.

The Underlying Properties are operated for natural gas production only and are focused exclusively in the Marcellus Shale formation in Greene
County, Pennsylvania. In particular, the concentration of the Underlying Properties in the Marcellus Shale formation in Greene County could disproportionately expose the Trust's interests to
operational and regulatory risk in that area. Due to the lack of diversification in industry type and location of the Trust's interests, adverse developments in the natural gas market or the area of
the Underlying Properties could have a significantly greater impact on the Trust's financial condition, results of operations and cash flows than if the Trust's Royalty Interests were more
diversified.

The Trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.

The existence of a material title deficiency with respect to the Underlying Properties can reduce the value or render a property worthless, thus
adversely affecting the distributions to unitholders. Greylock does not obtain title insurance covering mineral leaseholds. Additionally, undeveloped acreage has greater risk of title defects than
developed acreage.

Prior
to the drilling of the PUD Wells, Legacy ECA obtained preliminary title reviews to ensure there were no obvious defects in title to the leasehold. However, a title review is not
title insurance, and in the event of a material title problem in the future, proceeds available for distribution to unitholders, and the value of the Trust units, may be reduced.

The Trust is passive in nature and has no stockholder voting rights in Greylock, managerial, contractual or
other ability to influence Greylock, or control over the field operations of, sale of natural gas from, or development of, the Underlying Properties.

Neither the Trust nor the Trust unitholders has any voting rights with respect to Greylock and therefore none of them has any managerial,
contractual or other ability to influence Greylock's activities or operations of the natural gas properties. This is how, pursuant to the Administrative Services Agreement and the Development
Agreement, Legacy ECA was able to transfer operations of all of the Trust properties to Greylock, who also retains the right to transfer operations of any or all of the Trust properties. Any
third-party operators may not have the operational expertise of Greylock within the AMI. Natural gas properties are typically managed pursuant to an operating
agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the
interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production,
compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders has any contractual ability to influence or control the field
operations of, sale of natural gas from, or any future development of, the Underlying Properties. The Trust units are a passive investment that entitles the Trust only to receive cash distributions
attributable to the Royalty Interests.

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Greylock may sell all or a portion of the Underlying Properties, subject to and burdened by the Royalty
Interests, and any such purchaser could have a weaker financial position and/or be less experienced in natural gas development and production than Greylock.

Trust unitholders will not be entitled to vote on any sale of the Underlying Properties if the Underlying Properties are sold subject to and
burdened by the Royalty Interests and the Trust will not receive any proceeds from any such sale. The purchaser would be responsible for all of Greylock's obligations relating to the Royalty Interests
on the portion of the Underlying Properties sold, and Greylock would have no continuing obligation to the Trust for those properties. Additionally, Greylock may enter into farmout or joint venture
arrangements with respect to the wells burdened by the Royalty Interests. Any purchaser, farmout counterparty or joint venture partner could have a weaker financial position and/or be less experienced
in natural gas development and production than Greylock.

The natural gas reserves estimated to be attributable to the Underlying Properties of the Trust are depleting
assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and gas properties or Royalty Interests to replace the depleting assets
and production.

The proceeds payable to the Trust from the Royalty Interests are derived from the sale of the production of natural gas from the Underlying
Properties. The natural gas reserves attributable to the Underlying Properties are depleting assets, which means that the reserves of natural gas attributable to the Underlying Properties will decline
over time. As a result, the quantity of natural gas produced from the Underlying Properties will decline over time. Based on the estimated production volumes in the original reserve report described
in the Prospectus, the gas production from proved producing reserves attributable to the PDP Royalty Interest was projected to decline at an average rate of approximately 8.5% per year over the life
of the Trust. With respect to the PUD Wells, as of the
Trust formation date, the production rate was expected to decline approximately 37.3% during the first year of production, approximately 14.7% during the next three to five years of production and
approximately 8.0% per year for the remainder of the economically productive life of the well. These production characteristics were generally consistent with other development wells in the AMI. The
anticipated rate of decline as originally projected was an estimate and actual decline rates may vary from those estimates. The average decline rate for the 40 PUD Wells for which Greylock now has
several years of production data was about 43.5% during the first year.

Future
maintenance may affect the quantity of Proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these
projects will depend on, among other factors, the market prices of natural gas. Greylock has no contractual obligation to make capital expenditures on the Underlying Properties in the future.
Furthermore, for properties on which Greylock is not designated as the operator, Greylock has no control over the timing or amount of those capital expenditures. Greylock also has the right to
non-consent and not participate in the capital expenditures on properties for which it is not the operator, in which case Greylock and the Trust will not receive the production resulting from such
capital expenditures. If Greylock or other operators of the wells to which the Underlying Properties relate do not implement maintenance projects when warranted, the future rate of production decline
of Proved reserves may be higher than the rate currently expected by Greylock or estimated in the reserve report.

The
Trust Agreement provides that the Trust's business activities are limited to owning the Royalty Interests and any activity reasonably related to such ownership, including activities
required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not permitted to acquire other oil and gas properties or royalty interests to replace
the depleting assets and production attributable to the Trust.

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The amount of cash available for distribution by the Trust will be reduced by the amount of post-production
costs, applicable taxes associated with the Trust's interest, and Trust expenses.

The Royalty Interests and the Trust bear certain costs and expenses that reduce the amount of cash received by the Trust or available for
distribution by the Trust to the holders of the Trust units. These costs and expenses include those described below.



The
amount of costs and expenses borne by the Trust may vary materially from quarter-to-quarter. The extent by which the costs and expenses described above are higher or lower in any
quarter will directly decrease or increase the amount received by the Trust and available for distribution to the unitholders.

A decrease in the differential between the price realized by Greylock for natural gas produced from the
Underlying Properties and the NYMEX or other benchmark price of natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of Trust units.

During the first few years of the Trust's existence, prices received for natural gas production from Trust properties exceeded the relevant
benchmark prices, such as NYMEX; however, since 2014 the prices received have been lower than the benchmark prices, and this dynamic could continue in the future. The difference between the price
received and the benchmark price is called a differential. The

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differential
may vary significantly due to market conditions, the quality and location of production and other factors. Greylock cannot accurately predict natural gas differentials. Further decreases
in the differential between the realized price of natural gas and the benchmark price for natural gas could reduce the proceeds to the Trust and, accordingly, reduce the cash distributions by the
Trust and the value of the Trust units.

The Trust has no hedges in place to protect against the price risk inherent in holding interest in natural
gas, a commodity that is frequently characterized by significant price volatility.

At the formation of the Trust, approximately fifty percent of the estimated natural gas production attributable to the Royalty Interests was
hedged from April 1, 2010 through March 31, 2014. From inception through the termination of the hedge arrangements, the Trust received approximately $35 million that it would not
have received without the hedge arrangements. The last of the hedge arrangements expired March 31, 2014. Consequently, unitholders no longer have the benefit of any hedge arrangements, and all
production is subject to the price risks inherent in holding interests in natural gas, a commodity that is frequently characterized by significant price volatility.

Natural gas wells are subject to operational hazards that can cause substantial losses. Greylock maintains
insurance but may not be adequately insured for all such hazards.

There are a variety of operating risks inherent in natural gas production and associated activities, such as fires, leaks, explosions,
mechanical problems, major equipment failures, blow-outs, uncontrollable flow of natural gas, water or drilling fluids, casing collapses, abnormally pressurized formations and natural disasters. The
occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of natural gas at any of the Underlying Properties will reduce Trust distributions by
reducing the amount of proceeds available for distribution.

Additionally,
if any of such risks or similar accidents occur, Greylock could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property,
natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If Greylock experiences any of these problems, its ability to conduct
operations and perform its obligations to the Trust could be adversely affected. While Greylock maintains insurance coverage it deems appropriate for these risks with respect to the Underlying
Properties, Greylock's operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance. If a well is damaged, Greylock would have no obligation to drill
a replacement well or make the Trust whole for the loss. The Trust does not maintain any type of insurance against any of the risks of conducting oil and gas exploration and production or related
activities.

The Trustee may, under certain circumstances, sell the Royalty Interests and dissolve the Trust. Unless
sooner terminated, the Trust will begin to terminate following the end of the 20-year period in which the Trust owns the Term Royalty Interests.

The Trustee must sell the Royalty Interests if unitholders approve the sale or vote to dissolve the Trust. The Trustee must also sell the
Royalty Interests if the gross proceeds to the Trust attributable to the Royalty Interests over any four consecutive quarters are less than $1.5 million. Sale of all the Royalty Interests will
result in the dissolution of the Trust. The net proceeds of any such sale will be distributed to the Trust unitholders. Unless sooner terminated, the Trust will begin to liquidate on the Termination
Date. The Trust unitholders will not be entitled to receive any proceeds from the sale of production from the Underlying Properties following such date. The Term Royalty Interests will automatically
revert to Greylock at the Termination Date, while the Perpetual Royalty Interests will be sold and the proceeds will be distributed to the unitholders (including Greylock to the extent of any Trust
units it owns) at the Termination Date or soon thereafter. Greylock has a right of first refusal to purchase the Perpetual Royalty Interests upon termination of the Trust.

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If the Trust cannot meet the New York Stock Exchange continued listing requirements, the NYSE may delist the
common units.

The Trust's common units are currently listed on the NYSE. In the future, if the Trust is unable to meet the continued listing requirements of
the NYSEwhich require, among other things, that the average closing price of the common units remain at or above $1.00 over 30 consecutive trading daysthe common units could
be delisted if the Trust is unable to regain compliance. A delisting of our common units could negatively impact the Trust by, among other things, reducing the liquidity and market price of the common
units and reducing the number of investors willing to hold or acquire the common units.

The Private Investors may sell additional Trust units, and such sales could have an adverse effect on the
trading price of the common units.

As of December 31, 2017, Greylock held no common units, while select Private Investors held common units. In connection with the Trust's
formation, the Trust and the Private Investors entered into a registration rights agreement, pursuant to which the Trust in 2012 filed a registration statement on Form S-3, to facilitate sales
of common units by such holders. If the Private Investors were to sell or offer to sell a substantial number of common units, the market price of the units could be adversely affected.

Conflicts of interest could arise between Greylock and the Trust unitholders.

As a working interest owner in the Underlying Properties, Greylock could have interests that conflict with the interests of the Trust and the
Trust unitholders. For example:



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The Trust is administered by a Trustee who cannot be replaced except at a special meeting of Trust
unitholders.

The business and affairs of the Trust are administered by the Trustee. Voting rights of Trust unitholders are more limited than those of
stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust
Agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the outstanding Trust units, including Trust units held by Greylock, if any, at a special meeting
of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it will be difficult for public unitholders to remove or replace the
Trustee without the cooperation of Greylock (if at the time it holds a significant percentage of total Trust units) or other holders of a substantial percentage of the outstanding Trust units.

Trust unitholders have limited ability to enforce provisions of the Royalty Interests, and Greylock's
liability to the Trust is limited.

The Trust Agreement permits the Trustee and the Trust to sue Greylock or any other future owner of the Underlying Properties to enforce the
terms of the conveyances creating the
PDP and PUD Royalty Interests. If the Trustee does not take appropriate action to enforce provisions of these conveyances, Trust unitholders' recourse would be limited to bringing a lawsuit against
the Trustee to compel the Trustee to take specified actions. The Trust Agreement expressly limits a Trust unitholder's ability to directly sue Greylock or any other third party other than the Trustee.
As a result, Trust unitholders will not be able to sue Greylock or any future owner of the Underlying Properties to enforce these rights. Furthermore, the Royalty Interest conveyances provide that,
except as set forth in the conveyances, Greylock is not liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good faith.

Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under
Delaware law.

Under the Delaware Statutory Trust Act, Trust unitholders will be entitled to the same limitation of personal liability extended to stockholders
of corporations under the General Corporation Law of the State of Delaware. Nevertheless, courts in jurisdictions outside of Delaware may not give effect to such limitation.

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

Greylock's natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order
to conduct its operations in compliance with these laws and regulations, Greylock must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and
local governmental authorities and engage in extensive

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reporting.
Greylock may incur substantial costs in order to maintain compliance with these existing laws and regulations. Further, in light of the explosion and fire on the drilling rig Deepwater
Horizon in the Gulf of Mexico, as well as recent incidents involving the release of natural gas and fluids as a result of drilling activities in the Marcellus Shale, there has been a variety of
regulatory initiatives at the federal and state level to restrict oil and gas drilling operations in certain locations. Any increased regulation or suspension of oil and gas exploration and
production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs. Such costs or
significant delays could have a material adverse effect on Greylock's
business, financial condition and results of operations. Greylock must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent Greylock is a
shipper on interstate pipelines, it must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.

Laws
and regulations governing natural gas exploration and production may also affect production levels. Greylock is required to comply with federal and state laws and regulations
governing conservation matters, including provisions related to the unitization or pooling of the natural gas properties; the establishment of maximum rates of production from natural gas wells; the
spacing of wells; the plugging and abandonment of wells; and removal of related production equipment. These and other laws and regulations can limit the amount of natural gas Greylock can produce from
its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and actual
future net revenues to the Trust and estimates of reserves attributable to the Trust's interests.

Pennsylvania
historically has not imposed a severance tax on the production of natural gas. However, over the past few years there have been several proposals to initiate one. Most
recently, in February 2016 the Governor of Pennsylvania proposed a flat 6.5 percent severance tax on the value of natural gas at the wellhead. Under the Governor's current proposal, the amount
paid in impact fees paid on unconventional gas wells could be taken as a credit against the severance tax. Prior proposals included severance taxes of 5 percent, later reduced to
3.5 percent, plus 4.7 cents per thousand cubic feet of natural gas extracted. Any such severance tax, if adopted, would be a cost that would be borne by the Trust and could materially reduce
distributions to unitholders.

New
laws or regulations, or changes to existing laws or regulations, may unfavorably impact Greylock, could result in increased operating costs and have a material adverse effect on
Greylock's financial condition and results of operations. For example, Congress has previously considered legislation that, if adopted in its proposed form, would subject companies involved in natural
gas and oil exploration and production activities to, among other items the elimination of most U.S. federal tax incentives and deductions available to natural gas exploration and production
activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. Additionally, the Pennsylvania Environmental Quality Board has proposed
amendments to Pennsylvania's oil and gas regulations to update existing requirements regarding the drilling, casing, cementing, testing, monitoring and plugging of oil and gas wells, and the
protection of water supplies, including reporting the list of chemicals used in hydraulic fracturing or to stimulate the well.

Additionally,
state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on
the part of Greylock and third party downstream natural gas transporters. These and other potential regulations could increase Greylock's operating costs, reduce Greylock's liquidity, delay Greylock's
operations, increase direct and third party post production costs associated with the Trust's interests or otherwise alter the way Greylock conducts its business, which could have a material adverse
effect on Greylock's financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid by Greylock for
transportation on downstream interstate pipelines.

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The ability of Greylock to satisfy its obligations to the Trust depends on the financial position of
Greylock, and in the event of a default by Greylock in its obligations to the Trust, or in the event of Greylock's bankruptcy, it would be expensive and time-consuming for the Trust to exercise its
remedies.

Greylock is a privately held, independent energy company engaged in the exploration, development, production, gathering and aggregation and sale
of natural gas and oil, primarily in the Appalachian Basin, Gulf Coast and Rocky Mountain regions in the United States. Greylock is also the operator of all of the Producing Wells and all of the PUD
Wells. The conveyances also provide that Greylock is obligated to market, or cause to be marketed, the natural gas production related to the Underlying Properties. Due to the Trust's reliance on
Greylock to fulfill these numerous obligations, the value of the Royalty Interests and its ultimate cash available for distribution will be highly dependent on Greylock's performance. Greylock is not
a reporting company and does not file periodic reports with the SEC. Therefore, Trust unitholders do not have access to financial information of Greylock.

The
ability of Greylock to perform its obligations to the Trust will depend on Greylock's future financial condition and economic performance and access to capital, which in turn will
depend upon the supply and demand for natural gas and oil, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of Greylock.

Due
to uncertainty under Pennsylvania law, the Royalty Interests conveyed by Greylock to the Trust might not be treated as real property interests, or as interests in hydrocarbons in
place or to be produced. As a result, the Royalty Interests might be treated as unsecured claims of the Trust against Greylock in the event of Greylock's bankruptcy. The Royalty Interest Lien is
intended to provide security to the Trust should the Royalty Interests be subject to such a challenge. If the PDP Royalty Interest or the PUD Royalty Interest were determined not to be a real property
interest owned by the Trust, the Trust's remedy would be to foreclose on the Trust's Royalty Interest Lien to cause the Trust to receive a volume of natural gas production from the Trust properties
calculated in accordance with the provisions of the conveyances of the Royalty Interests to the Trust. Foreclosure on the Royalty Interest Lien is exercisable only following a bankruptcy filing of
Greylock or its successor and based on an uncured payment default occurring under the conveyances of the Royalty Interests to the Trust existing at the time of, or occurring after, such bankruptcy
filing. The process of foreclosing to enforce the Royalty Interest Lien would be expensive and time-consuming, and the resulting delays and expenses could reduce Trust distributions substantially or
eliminate them for an unpredictable period of time.

The
proceeds of the Royalty Interests may be commingled, for a period of time, with proceeds of Greylock's retained interest. The Trust may not have adequate facts to trace its
entitlement to funds in the commingled pool of funds and that other persons may, in asserting claims against Greylock's retained interest, be able to assert claims to the proceeds that should be
delivered to the Trust. In addition, during a bankruptcy of Greylock, payments of the royalties may be delayed or deferred; in addition, the obligation to pay royalties may be disaffirmed or
cancelled. In either situation, the Trust may need to look to the Royalty Interest Lien to replace its rights under the Royalty Interests. During the pendency of any bankruptcy proceedings involving
Greylock, the Trust's ability to foreclose on the Royalty Interest Lien, and the ability to collect cash payments from customers being held in Greylock's accounts that are attributable to production
from the Trust properties, may be stayed by the bankruptcy court. Delay in realizing on the collateral for the Royalty Interest Lien is possible, and a bankruptcy court might not permit such
foreclosure. The bankruptcy also might delay the execution of a new agreement with another driller or operator. If the Trust were to enter into a new agreement with a drilling or operating partner,
the new partner might not achieve the same levels of production or sell natural gas at the same prices as Greylock was able to achieve.

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The operations of Greylock are subject to environmental laws and regulations that may result in significant
costs and liabilities.

The natural gas exploration and production operations of Greylock in the Marcellus Shale are subject to stringent and comprehensive federal,
state and local laws and regulations governing the discharge, emission or release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may
impose numerous obligations that are applicable to Greylock's operations including the acquisition of a permit before conducting drilling; water withdrawal or waste disposal operations; govern the
amounts and types of substances that may be disposed or released into the environment; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or
areas containing endangered or threatened species or their habitats; require investigatory and response actions to mitigate pollution conditions arising from Greylock's operations or attributable to
former operations; and impose obligations to reclaim and abandon well sites, impoundments and pits. Failure to comply with these laws and regulations may result in the assessment of administrative,
civil or criminal penalties; the imposition of investigatory or remedial obligations and the issuance of orders enjoining some or all of Greylock's operations in affected areas.

There
is inherent risk of incurring significant environmental costs and liabilities in the performance of Greylock's operations due to its handling of petroleum hydrocarbons and wastes,
because of air emissions and wastewater discharges related to its operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and
regulations, Greylock could be subject to joint and several strict liabilities for the removal or remediation of previously
released materials or property contamination regardless of whether Greylock was responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the
time those actions were taken. Private parties, including the owners of properties upon which Greylock's wells are drilled and facilities where Greylock's petroleum hydrocarbons or wastes are taken
for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance with environmental laws and regulations or for personal
injury or property damage or to recover some or all of the costs of the removal or remediation of released materials. In addition, the risk of accidental spills or releases could expose Greylock to
significant liabilities that could have a material adverse effect on its financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes
that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require Greylock to make significant expenditures to attain and maintain compliance
and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition. Greylock may not be able to recover some or any of these costs from
insurance.

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

In December 2009, the EPA published its findings that emissions of GHGs present a danger to public health and the environment. These findings
allow the agency to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that
could trigger permit review for GHG emissions from certain stationary sources. Those regulations were challenged in federal court and the Supreme Court has upheld the EPA's authority to regulate GHG
emissions from stationary sources, concluding sources that trigger air permitting requirements based on their traditional criteria pollutant emissions must include a limit for GHGs in their permit.
The EPA has also issued regulations that require the establishment and reporting of an inventory of GHG emissions from specified stationary sources, including certain onshore oil and natural gas
exploration, development and production facilities. In

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October
2015, the EPA finalized its "Clean Power Plan" regulations under Section 111(d) of the Clean Air Act to limit GHG emissions from existing power plants. Several states, trade groups and
companies have challenged the legality of the EPA's Section 111(d) rule for existing power plants in federal court. On February 9, 2016, the Supreme Court granted an emergency stay
preventing EPA from implementing the Clean Power Plan until the D.C. Circuit issues a decision on the legality of the rule and disposition of a writ of certiorari, to the extent such a writ is sought.
President Trump has publicly stated that it is a top priority of his administration to eliminate the Clean Power Plan. The EPA has finalized regulations that require control of methane emissions from
new sources in the oil and gas industry and
target ozone-forming pollutants from existing sources in areas that do not meet federal ozone health standards. The EPA has also issued several Information Collection Requests to industry seeking
assistance in developing a program for regulating methane emissions from existing oil and gas sources as well.

At
the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to control or
reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, Greylock's equipment and operations could require
Greylock to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas that it produces. Finally, some scientists have concluded that
increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods
and other climatic events; if any such effects were to occur, they could have an adverse effect on Greylock's assets and operations.

Tax Risks Related to the Trust's Common Units

The Trust's tax treatment depends on its status as a partnership for United States federal income tax
purposes. At the inception of the Trust, the Trust received an opinion from tax counsel that the Trust will be treated as a partnership for United States federal income tax purposes. If the Internal
Revenue Service were to treat the Trust as a corporation for United States federal income tax purposes, then its cash available for distribution to you would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the Trust units depends largely on the Trust being treated as a partnership for
United States federal income tax purposes. At the inception of the Trust, Legacy ECA and the Trust received an opinion from tax counsel that the Trust would be treated as a partnership for United
States federal income tax purposes. In order for the Trust to be treated as a partnership for United States federal income tax purposes, current law requires that 90% or more of our gross income for
every taxable year consist of "qualifying income," as defined in Section 7704 of the Internal Revenue Code. The Trust may not meet this requirement or current law may change so as to cause, in
either event, the Trust to be treated as a corporation for United States federal income tax purposes or otherwise subject the Trust to taxation as an entity. Although the Trust does not believe based
upon its current activities that it is so treated, a change in current law could cause it to be treated as a corporation for United States federal income tax purposes or otherwise subject it to
taxation as an entity. The Trust has not requested, and does not plan to request, a ruling from the Internal Revenue Service, which we referred to as the IRS, on this or any other tax matter affecting
it.

If
the Trust was treated as a corporation for United States federal income tax purposes, it would pay United States federal income tax on its taxable income at the corporate tax rate,
which is currently a maximum of 21%, and would likely be required to pay state income tax. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses,
deductions or credits would flow through to you. Because a tax would be imposed upon the Trust as a corporation, its cash available for distribution to you would be substantially reduced. Therefore,
treatment of the Trust as a

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corporation
would result in a material reduction in the anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of the Trust units.

The
Trust Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to taxation as a corporation or otherwise subjects it
to entity-level taxation for United States federal income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law on the Trust.

If the Trust were subjected to a material amount of additional entity-level taxation by Pennsylvania or any
other states, the Trust's cash available for distribution to you would be reduced.

The Trust was historically required to pay Pennsylvania franchise tax on its capital stock value, as determined pursuant to the statute and
apportioned to Pennsylvania. The tax rate of 0.045% was completely phased out effective January 1, 2016, though it could be readopted by the General Assembly in its annual budget process.
Changes in current state law may subject the Trust to additional entity-level taxation by Pennsylvania or other states. Because of widespread state budget deficits and other reasons, several states
are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any additional taxes on the Trust may
substantially reduce the cash available for distribution to you and, therefore, negatively impact the value of an investment in the Trust units.

If enacted, severance taxes in Pennsylvania could materially increase the applicable taxes that are borne by
the Trust.

Although Pennsylvania historically has not imposed a severance tax on the production of natural gas, in February 2016 the Governor of
Pennsylvania proposed a flat 6.5 percent severance tax on the value of natural gas at the wellhead. Under the Governor's current proposal, the amount paid in impact fees paid on unconventional
gas wells could be taken as a credit against the severance tax. Prior proposals included severance taxes of 5 percent, later reduced to 3.5 percent, plus 4.7 cents per thousand cubic
feet of natural gas extracted. Any such severance tax, if adopted, would be a cost that would be borne by the Trust and could materially reduce distributions to unitholders.

The tax treatment of publicly traded partnerships or an investment in our Trust units could be affected by
recent and potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The current United States federal income tax treatment of publicly traded partnerships, including the Trust, or an investment in the Trust
units, may be modified by administrative, legislative or judicial interpretation at any time. In the past, Congress has considered substantive changes to the existing United States federal income tax
laws that affect certain publicly traded partnerships. Any modification to the United States federal income tax laws or interpretations thereof could cause the Trust to be taxed as a corporation or
make it difficult or impossible to meet the requirements for the Trust to be treated as a partnership for United States federal income tax purposes, affect or cause us to change our business
activities, affect the tax considerations of an investment in the Trust, change the character or treatment of portions of the Trust income and adversely affect an investment in the Trust's units.
Moreover, any modification to the United States federal income tax laws and interpretations thereof may or may not be applied retroactively. Any potential change in law or interpretation thereof could
negatively impact the value of an investment in the Trust units.

Under
current law for the taxable year ending December 31, 2017, the highest marginal United States federal income tax rate applicable to ordinary income of individuals is 39.6%
and the highest marginal United States federal income tax rate applicable to long-term capital gains (generally, capital

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gains
on certain assets held for more than 12 months) of individuals is 20%. These rates are subject to change by new legislation at any time.

In
addition, a 3.8% Medicare tax is imposed on certain net investment income from a variety of sources earned by individuals. For these purposes, net investment income generally includes
a Trust unitholder's allocable share of the Trust income and gain realized by a Trust unitholder from a sale of the Trust units. The tax will be imposed on the lesser of (i) the Trust
unitholder's net income from all investments, or (ii) the amount by which the Trust unitholder's adjusted gross income exceeds $250,000 (if the Trust unitholder is married and filing jointly)
or $200,000 (if the Trust unitholder is unmarried).

Recently
enacted federal legislation applicable to the Trust for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also
alters the procedures for assessing and collecting income taxes due (including applicable penalties and interest) as a result of an audit. Unless the Trust is eligible to (and chooses to) elect to
issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect income taxes (including any applicable penalties and interest)
directly from the Trust in the year in which the audit is completed under the new rules. If the Trust is required to pay income taxes, penalties and interest as the result of audit adjustments, cash
available for distribution to Trust unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, Trust unitholders during
that taxable year would bear the expense of the adjustment even if they were not Trust unitholders during the audited taxable year.

The Trust prorates items of income, gain, loss and deduction between transferors and transferees of the Trust
units each month based upon the ownership of the Trust units on the first day of each month, instead of on the basis of the date a particular unit is transferred.

The Trust prorates items of income, gain, loss and deduction between transferors and transferees of the Trust units each month based upon the
ownership of the Trust units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing
Treasury Regulations, and, accordingly, the Trust's counsel was unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we
may be required to change the allocation of items of income, gain, loss and deduction among the Trust unitholders. If the IRS contests the federal income tax positions the Trust takes, the market for
the Trust units may be adversely impacted, the cost of any IRS contest will reduce the Trust's cash available for distribution to you and items of income, gain, loss and deduction may be reallocated
among Trust unitholders.

If the IRS contests the United States federal income tax positions the Trust takes, the market for the Trust
units may be adversely impacted and the cost of any IRS contest will reduce the Trust's cash available for distribution to you.

The Trust has not requested a ruling from the IRS with respect to its treatment as a partnership for United States federal income tax purposes
or any other matter affecting the Trust. The IRS may adopt positions that differ from the conclusions of the Trust's counsel expressed in the Prospectus or from the positions the Trust takes. It may
be necessary to resort to administrative or court proceedings to attempt to sustain some or all of the conclusions of the Trust's counsel or the positions the Trust takes. A court may not agree with
some or all of the conclusions of the Trust's counsel or positions the Trust takes. Any contest with the IRS may materially and adversely impact the market for the Trust units and the price at which
they trade. In addition, the Trust's costs of any contest with the IRS will be borne indirectly by the Trust unitholders because the costs will reduce the Trust's cash available for distribution.

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You will be required to pay taxes on your share of the Trust's income even if you do not receive any cash
distributions from the Trust.

Because the Trust unitholders will be treated as partners to whom the Trust will allocate taxable income which could be different in amount than
the cash the Trust distributes, you will be required to pay any United States federal income taxes and, in some cases, state and local income taxes on your share of the Trust's taxable income even if
you receive no cash distributions from the Trust. You may not receive cash distributions from the Trust equal to your share of the Trust's taxable income or even equal to the actual tax liability that
result from that income.

Tax gain or loss on the disposition of the Trust units could be more or less than expected.

If you sell your Trust units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those
Trust units. Because distributions in excess of your allocable share of the Trust's net taxable income decrease your tax basis in your Trust units, the amount, if any, of such prior excess
distributions with respect to the Trust units you sell will,
in effect, become taxable income to you if you sell such Trust units at a price greater than your tax basis in those Trust units, even if the price you receive is less than your original cost.
Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion recapture.

Tax-exempt entities and non-United States persons face unique tax issues from owning the Trust units that may
result in adverse tax consequences to them.

Investment in Trust units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-United States persons raises
issues unique to them. For example, some of the Trust income allocated to organizations exempt from United States federal income tax, including IRAs and other retirement plans, may be unrelated
business taxable income which would be taxable to them. Distributions to non-United States persons may be reduced by withholding taxes at the highest applicable effective tax rate, and non-United
States persons may be required to file United States federal income tax returns and pay tax on their share of the Trust's taxable income.

The Trust will treat each purchaser of Trust units as having the same economic attributes without regard to
the actual Trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.

Due to a number of factors, including the Trust's inability to match transferors and transferees of Trust units, the Trust will adopt positions
that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could
affect the timing of these tax benefits or the amount of gain from your sale of Trust units and could have a negative impact on the value of the Trust units or result in audit adjustments to your tax
returns.

A Trust unitholder whose Trust units are loaned to a "short seller" to cover a short sale of Trust units may
be considered as having disposed of those Trust units. If so, he would no longer be treated for tax purposes as a partner with respect to those Trust units during the period of the loan and may
recognize gain or loss from the disposition.

Because a Trust unitholder whose Trust units are loaned to a "short seller" to cover a short sale of Trust units may be considered as having
disposed of the loaned Trust units, the Trust unitholder may no longer be treated for United States federal income tax purposes as a partner with respect to those Trust units during the period of the
loan to the short seller and the unitholder
may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of the Trust's

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income,
gain, loss or deduction with respect to those Trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Trust units could be fully
taxable as ordinary income. The Trust's counsel has not rendered an opinion regarding the treatment of a unitholder where Trust units are loaned to a short seller to cover a short sale of Trust units;
therefore, Trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account
agreements to prohibit their brokers from loaning their Trust units.

The Trust will adopt certain valuation methodologies that may affect the income, gain, loss and deduction
allocable to the Trust unitholders. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.

The United States federal income tax consequences of the ownership and disposition of Trust units will depend in part on the Trust's estimates
of the relative fair market values, and the initial tax bases of the Trust's assets. Although the Trust may from time to time consult with professional appraisers regarding valuation matters, the
Trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the
estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Trust unitholders might change,
and Trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments. It also could affect the amount of gain from
unitholders' sale of Trust units and could have a negative impact on the value of the Trust units or result in audit adjustments to unitholders' tax returns without the benefit of additional
deductions.

The sale or exchange of 50% or more of the Trust's capital and profits interests during any twelve-month
period will result in the termination of the Trust's partnership status for United States federal income tax purposes.

The Trust will be considered to have technically terminated for United States federal income tax purposes if there is a sale or exchange of 50%
or more of the total interests in its capital and profits within a twelve-month period. For purposes of determining whether the 50%
threshold has been met, multiple sales of the same Trust unit within any twelve-month period will be counted only once. The Trust's termination would, among other things, result in the closing of its
taxable year for all Trust unitholders, which would result in the Trust filing two tax returns (and the Trust unitholders could receive two Schedules K-1) for one calendar year. The IRS has
previously announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be
required to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs. In the case of a unitholder reporting on a taxable year other than a calendar
year ending December 31, the closing of the Trust's taxable year may also result in more than twelve months of the Trust's taxable income being includable in his taxable income for the year of
termination. A technical termination would not affect the Trust's classification as a partnership for United States federal income tax purposes, but instead, the Trust would be treated as a new
partnership for tax purposes. If treated as a new partnership, the Trust must make new tax elections and could be subject to penalties if the Trust is unable to determine that a technical termination
occurred.

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Certain United States federal income tax preferences currently available with respect to natural gas
production may be eliminated as a result of future legislation.

In recent years, the U.S. government's budget proposals and other proposed legislation have included the elimination of certain key U.S. federal
income tax incentives currently available to oil and natural gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers
engaged in the exploration or production of natural resources. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas
properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for U.S. production activities and
(iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and natural gas
within the U.S. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other
similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

Item 1B.Unresolved Staff Comments.

None.

Item 2.Properties.

The Underlying Properties

The Underlying Properties consist of the working interests owned by Greylock and the Private Investors in the Marcellus Shale formation in
Greene County, Pennsylvania arising under leases and farmout agreements related to properties from which the PDP Royalty Interest and the PUD Royalty Interest were conveyed. As of December 31,
2017, the total natural gas reserves attributable to the Trust interests were 38.2 Bcf. Greylock continues to be the operator of all of the wells subject to the Royalty Interests although it is not
contractually obligated to the Trust to remain so. The reserves attributable to the Royalty Interests include the reserves that are expected to be produced from the Marcellus Shale formation (subject
to the terms of the conveyances creating the Net Profits Interests) during the remaining portion of the 20-year period in which the Trust owns the Royalty Interests as well as the residual interest in
the reserves that the Trust will sell on or shortly following the Termination Date.

Natural Gas Reserves

Ryder Scott estimated natural gas reserves attributable to the Royalty Interests as of December 31, 2017. Numerous uncertainties are
inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of the reserves may vary significantly from the estimates.

Proved reserves of the Royalty Interests.The following table sets forth, certain estimated Proved reserves, estimated future net cash
flows and the
discounted present value thereof attributable to the Royalty Interests, as of December 31, 2017, in each case derived from the Ryder Scott reserve report. The reserve report was prepared by
Ryder Scott in accordance with criteria established by the SEC. In accordance with the SEC's rules, the reserves presented below were determined using the twelve-month unweighted arithmetic average of
the first-day-of-the-month price for the period from January 1, 2017 through December 31, 2017, without giving effect to any derivative transactions, and were held constant for the life
of the properties. This yielded an average realized price for natural gas of $2.63 per Mcf. The net revenues attributable to the Trust's reserves are net of the Trust's obligation to reimburse
Greylock for post-production costs. The reserves and cash flows attributable to the Trust's interests include only the reserves attributable to the Underlying Properties that are expected to be
produced

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within
the remaining portion of the 20-year period in which the Trust owns the Royalty Interests as well as the residual interest in the reserves that the Trust will own on the Termination Date. A
summary of the Ryder Scott reserve report dated January 18, 2018 is included as Appendix A to this report.



Proved reserves

Proved Gas
Reserves
(MMcf)

Estimated
Future Net
Cash Flows

Discounted
Estimated
Future Net
Cash Flows(1)(Dollars in thousands)Royalty Interests:Proved Developed


38,177

$
73,930

$
37,186


(1)The
present values of future net cash flows for the Royalty Interests were determined using a discount rate of 10% per annum.


Information
concerning historical changes in net Proved reserves attributable to the Royalty Interests, and the calculation of the standardized measure of discounted future net cash
flows related thereto, is contained in the unaudited supplemental information contained elsewhere in this report. The Trust has not filed reserve estimates covering the Royalty Interests with any
other federal authority or agency.

The Reserve Report

Technologies.The reserve report was prepared using decline curve analysis to determine the reserves of individual Producing Wells.

Internal Controls.Ryder Scott, the independent petroleum engineering consultant, estimated, in accordance with appropriate engineering,
 geologic,
and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry, and definitions and guidelines established by the SEC, all of the proved
reserve information in this report. These reserves estimation methods and techniques are widely taught in university petroleum curricula and throughout the industry's ongoing training programs.
Although these appropriate engineering, geologic, and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry are based upon established
scientific concepts, the application of such principles involves extensive judgment and is subject to changes in existing knowledge and technology, economic conditions and applicable statutory and
regulatory provisions. These same industry wide applied techniques are used in determining our estimated reserve quantities. The technical persons responsible for preparing the reserves estimates
presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Society of Petroleum Engineers' Standards Pertaining to the Estimating
and Auditing of Oil and Gas Reserves Information. Greylock's internal control over its reserve reporting process is designed to result in accurate and reliable estimates in compliance with applicable
regulations and guidance. Internal reserve preparation is performed by staff reservoir engineers and geoscientists before review by the Reservoir Engineering Manager. These individuals consult
regularly with Ryder Scott during the reserve estimation process to review properties, assumptions, and any new data available. Additionally, Greylock's senior management reviewed and approved all
Ryder Scott reserve reports contained herein.

Greylock's
reserves are reviewed by the Reservoir Engineering Manager. The Reservoir Engineering Manager has a Bachelor of Science degree in Petroleum Engineering. She has over five
years of oil and gas industry experience in Reservoir Engineering. During that time, she has focused on reserves estimates and economics.

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Sale and Abandonment of Underlying Properties

Greylock and any transferee will have the right to abandon its interest in any well or property composing a portion of the Underlying Properties
if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the potential conflict of interest between Greylock
and the Trust in determining whether a well is capable of producing in commercially paying quantities, Greylock is required under the applicable conveyance to act as a reasonably prudent operator in
the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as a burden affecting such property.

Greylock
generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Royalty Interests, without the consent of the Trust
unitholders. In addition, Greylock may, without the consent of the Trust unitholders, require the Trust to release Royalty Interests with an aggregate value to the Trust not to exceed
$5.0 million during any twelve-month period. These releases will be made only in connection with a sale by Greylock of the Underlying Properties and are conditioned upon the Trust receiving an
amount equal to the fair value to the Trust of such Royalty Interests. Greylock operates all of the wells subject to the Royalty Interests although it is not contractually obligated to the Trust to
continue as the operator. Any net sales proceeds paid to the Trust are distributable to Trust unitholders for the quarter in which they are received. Greylock has not identified for sale any of the
Underlying Properties.

Title to Properties

The Underlying Properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and
obligations affect Greylock's rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the Trust's interests and in estimating
the size and the value of the reserves attributable to the Royalty Interests.

Legacy
ECA acquired its interests in the Underlying Properties through a variety of means, including through the acquisition of oil and gas leases by Legacy ECA directly from the mineral
owner, through assignments of oil and gas leases to Legacy ECA by the lessee who originally obtained the leases from the mineral owner, through Farmout agreements that grant Legacy ECA the right to
earn interests in the properties covered by such agreements by drilling wells, and through acquisitions of other oil and gas interests by Legacy ECA. These interests were all acquired by Greylock as
part of the asset acquisition described in "Introduction" above.

Greylock's
interests in the natural gas properties composing the Underlying Properties are typically subject, in one degree or another, to one or more of the
following:



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Greylock
believes that the burdens and obligations affecting the Underlying Properties and the Royalty Interests are conventional in the industry for similar properties. Greylock also
believes that the burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the value of the Royalty
Interests.

Greylock
believes that its title to the Underlying Properties, and the Trust's title to the Royalty Interests, is good and defensible in accordance with standards generally accepted in
the oil and gas industry, subject to such exceptions as are not so material as to detract substantially from the use or value of such properties or Royalty Interests. Prior to drilling each PUD Well,
Greylock obtained a preliminary title review to ensure there were no obvious defects in title to the well. Greylock conducted a more thorough title examination of the drill site tract prior to
drilling any of the PUD Wells.

It
is unclear under Pennsylvania law whether the Royalty Interests would be treated as real property interests. Nevertheless, Greylock has recorded the conveyances of the Royalty
Interests in the real property records of Pennsylvania in accordance with local recording acts. Greylock also has granted to the Trust the Royalty Interest Lien to provide protection to the Trust, in
the event of a bankruptcy of Greylock, against the risk that the Royalty Interests were not considered real property interests.

Description of the Royalty Interests

The Royalty Interests were conveyed to the Trust by Legacy ECA by means of conveyance instruments that have been recorded in the appropriate
real property records in Greene County, Pennsylvania, where the natural gas properties to which the Underlying Properties relate are located. The PDP Royalty Interest burdens the existing working
interests now owned by Greylock in the Producing Wells. Greylock has an average working interest of approximately 93% in these wells.

The
PUD Royalty Interest initially burdened 50% of all of the interests of Legacy ECA in the Marcellus Shale formation in the AMI. Greylock's current interests in the natural gas
properties to which the PUD Wells relate consist of an average working interest of 100%. The conveyance related to the PUD Royalty Interest, however, provided that the proceeds from the PUD Wells
would be calculated on the basis that the PUD Wells were only burdened by interests that in total would not exceed 12.5%. If Greylock's interest in any of the wells subject to the PUD Royalty Interest
is subject to burdens in excess of 12.5%, such burdens will be fully allocated against Greylock's retained interest in such well, the net effect of which is that the Trust will receive payments with
respect to the PUD Royalty Interest as if the burdens affecting the PUD Wells were in total 12.5% (proportionately reduced).

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) Greylock's net revenue interest in the well. Greylock 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 Greylock owns a 100% working interest in a PUD Well, the applicable net revenue interest is

42

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Table of Contents

calculated
by multiplying Greylock'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 Greylock's working interest in a PUD Well is less
than 100%, the Trust's share of proceeds would be proportionately reduced.

PDP Royalty Interest.The conveyances creating the PDP Royalty Interest entitle the Trust to receive an amount of cash for each
calendar quarter
equal to 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of estimated natural gas production
attributable to the Producing Wells regardless of whether such amounts have actually been received by Greylock from the purchases of the natural gas produced. Proceeds from the sale of natural gas
production attributable to the Producing Wells in any calendar quarter means:



in
each case, after deducting the Trust's proportionate share of:



Proceeds
payable to the Trust from the sale of natural gas production attributable to the Producing Wells in any calendar quarter are not subject to any deductions for any expenses
attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production of natural gas attributable to the Producing Wells, including any costs to plug
and abandon a Producing Well.

PUD Royalty Interest.The conveyance creating the PUD Royalty Interest entitles the Trust to receive an amount of cash for each calendar
quarter
equal to 50% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of estimated natural gas production attributable to the PUD Wells regardless of whether such
amounts have actually been received by Greylock from the purchase of the natural gas produced. Proceeds from the sale of natural gas production, if any, attributable to the PUD Wells in any calendar
quarter means:



in
each case after deducting the Trust's proportionate share of:



43

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Table of Contents



Proceeds,
if any, payable to the Trust from the sale of natural gas attributable to the PUD Wells in any calendar quarter:



Royalty Interest Lien

Under the laws of Pennsylvania, it is not clear that the Royalty Interests conveyed by Greylock to the Trust would be treated as real property
interests. Therefore, Greylock has granted to the Trust a lien (the "Royalty Interest Lien") to provide protection to the Trust, exercisable in the event of a bankruptcy of Greylock, against the risk
that the Royalty Interests were not considered real property interests. More specifically, the Royalty Interest Lien is a lien in the Subject Interest and the Subject Gas, to the extent and only to
the extent that such Subject Interest and Subject Gas pertains to Gas in, under and that may be produced, saved or sold from the Marcellus Shale formation from the wellbore of the Producing Wells and
the PUD Wells, sufficient to cause the Trust to receive a volume of Trust Gas calculated in accordance with the provisions of the conveyances of the Royalty Interests.

The
Royalty Interest Lien does not include Greylock's retained interest in the PUD and Producing Wells and the AMI or other interest of Greylock in the AMI, and Greylock has the right to
lien, mortgage, sell or otherwise encumber the Greylock retained interest subject to the Royalty Interest Lien.

Greylock
has recorded the conveyances of the Royalty Interests and a Mortgage/Fixture Filing in the real estate records of Greene County, Pennsylvania and has filed a corresponding UCC-1
Financing Statement in the Office of the Secretary of State of West Virginia and the Commonwealth of Pennsylvania.

The
conveyances also provide that if Greylock's interest with respect to the PDP properties is greater than what was warranted to the Trust in the conveyances, Greylock will have the
right to offset against amounts owed to the Trust, the difference between what the Trust actually receives from PDP Royalty Interest and what the Trust should have received from the PDP Royalty
Interest had Greylock's interest been the amount warranted.

Additional Provisions

If a controversy arises as to the sales price of any production, then for purposes of determining gross
proceeds:



44

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Table of Contents



The
Trustee is not obligated to return any cash received from the Royalty Interests. However, any overpayments made to the Trust by Greylock due to adjustments to prior calculations of
proceeds or otherwise will reduce future amounts payable to the Trust until Greylock recovers the overpayments.

The
conveyances generally permit Greylock to sell, without the consent or approval of the Trust unitholders, all or any part of its interest in the Underlying Properties, if the
Underlying Properties are sold, subject to and burdened by the Royalty Interests. The Trust unitholders are not entitled to any proceeds of any sale of Greylock's interest in the Underlying Properties
that remains subject to and burdened by the Royalty Interests. Following any such sale, the proceeds attributable to the transferred property will be calculated pursuant to the conveyances as
described in this report, and paid by the purchaser or transferee to the Trust.

Greylock
or any transferee of an Underlying Property will have the right to abandon any well or property if it reasonably believes the well or property ceases to produce or is not
capable of producing in commercially paying quantities. In making such decisions, Greylock or any transferee of an Underlying Property is required under the applicable conveyance to act as a
reasonably prudent operator in the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as
burdens affecting such property. Upon termination of the lease, that portion of the Royalty Interests relating to the abandoned property will be extinguished.

Greylock
may, without the consent of the Trust unitholders, require the Trust to release Royalty Interests with an aggregate value to the Trust up to $5.0 million during any
twelve-month period. These releases will be made only in connection with a sale by Greylock of the Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value
to the Trust of such Royalty Interests.

Greylock
must maintain books and records sufficient to determine the amounts payable for the Royalty Interests to the Trust. Quarterly and annually, Greylock must deliver to the Trustee
a statement of the computation of the proceeds for each computation period as well as quarterly drilling and production results.

Item 3.Legal Proceedings.

None.

Item 4.Mine Safety Disclosures.

Not applicable.

45

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Table of Contents

PART II

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

The Trust units commenced trading on the New York Stock Exchange on July 1, 2010 under the symbol "ECT." The high and low closing sales
prices per unit for each quarter in 2016 and 2017 were as follows:



Quarter

High

Low2016First Quarter (January 1 through March 31)

$
1.54

$
0.98Second Quarter (April 1 through June 30)

$
2.03

$
1.36Third Quarter (July 1 through September 30)

$
2.32

$
1.91Fourth Quarter (October 1 through December 31)

$
2.59

$
2.052017First Quarter (January 1 through March 31)

$
2.80

$
2.05Second Quarter (April 1 through June 30)

$
2.30

$
2.00Third Quarter (July 1 through September 30)

$
2.51

$
2.10Fourth Quarter (October 1 through December 31)

$
2.50

$
2.05


At
December 31, 2017, the 17,605,000 units outstanding were held by 29 unitholders of record.

Distributions

Each quarter, the Trustee determines the amount of funds available for distribution to the Trust unitholders, as described elsewhere in this
report. Quarterly cash distributions during the term of the Trust are made by the Trustee generally no later than 60 days following the end of each quarter (or the next succeeding business day)
to the Trust unitholders of record on the 45th day following the end of each quarter (or the next succeeding business day). The table below presents, for each quarter of 2016 and 2017, the net
cash proceeds, the Trust expenses, and the resulting distributable income per Trust unit (dollars in thousands, except distributable income per unit).



31-Mar

30-Jun

30-Sep

31-Dec

Total2016Net proceeds

$
987

$
977

$
1,361

$
1,421

$
4,746General and administrative

$
548

$
482

$
116

$
123

$
1,269Distributable income

$
439

$
495

$
1,245

$
1,299

$
3,478Distributable income per common unit

$
0.025

$
0.028

$
0.071

$
0.074

$
0.1982017Net proceeds

$
2,054

$
2,012

$
1,448

$
1,361

$
6,875General and administrative

$
540

$
256

$
170

$
183

$
1,149Distributable income

$
1,516

$
1,756

$
1,280

$
1,179

$
5,731Distributable income per common unit

$
0.086

$
0.100

$
0.073

$
0.067

$
0.326


Subsequent
to year end, on or before February 28, 2018, a distribution of $0.067 per unit was paid to Trust common unitholders owning Trust common units as of February 20,
2018.

Equity Compensation Plans

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

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Table of Contents

Recent Sales of Unregistered Securities

None.

Purchases of Equity Securities

There were no purchases of Trust units by the Trust or any affiliated purchaser during the fourth quarter of 2017.

Item 6.Selected Financial Data.

The following is a summary of net proceeds, distributable income, and distributable income per unit by quarter in 2013, 2014, 2015, 2016, and
2017 (all amounts in thousands except distributable income per common unit):



31-Mar

30-Jun

30-Sep

31-Dec

Total2013Net proceeds

$
8,243

$
8,661

$
7,045

$
6,573

$
30,522Distributable income

$
7,802

$
8,397

$
6,881

$
6,372

$
29,452Distributable income per common unit

$
0.443

$
0.477

$
0.391

$
0.362

$
1.6732014Net proceeds

$
6,794

$
5,345

$
3,740

$
3,301

$
19,180Distributable income

$
5,887

$
4,951

$
3,572

$
3,165

$
17,575Distributable income per common unit

$
0.334

$
0.281

$
0.203

$
0.180

$
0.9982015Net proceeds

$
2,126

$
1,425

$
1,422

$
1,221

$
6,194Distributable income

$
1,477

$
1,077

$
1,274

$
1,170

$
4,998Distributable income per common unit

$
0.084

$
0.061

$
0.072

$
0.066

$
0.2832016Net proceeds

$
987

$
977

$
1,361

$
1,421

$
4,746Distributable income

$
439

$
495

$
1,245

$
1,299

$
3,478Distributable income per common unit

$
0.025

$
0.028

$
0.071

$
0.074

$
0.1982017Net proceeds

$
2,054

$
2,012

$
1,448

$
1,361

$
6,875Distributable income

$
1,516

$
1,756

$
1,280

$
1,179

$
5,731Distributable income per common unit

$
0.086

$
0.100

$
0.073

$
0.067

$
0.326


Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations.

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

Results of Trust Operations

For the twelve months ended December 31, 2017 compared to twelve months ended
December 31, 2016

Distributable income for the year ended December 31, 2017 increased to $5.7 million from $3.5 million for the year ended
December 31, 2016. Compared to the year ended December 31, 2016, royalty income increased $2.1 million and general and administrative expenses decreased by $0.1 million. No
cash reserves were withheld or released by the Trustee during the years ended December 31, 2017 and 2016.

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Table of Contents

Royalty
income increased from $4.8 million for the year ended December 31, 2016 to $6.9 million for the year ended December 31, 2017, an increase of
$2.1 million. This increase was due to an increase in the average realized price offset by a decrease in production.

The
average price realized for the year ended December 31, 2017 increased $0.80 per Mcf to $1.90 per Mcf as compared to $1.10 for the year ended December 31, 2016. The
increase in the average sales price for gas production was due in part to an increase in the weighted average monthly closing NYMEX price and in part to an increase to the average Basis. The average
sales price, before post-production costs, increased from $1.82 per Mcf for the year ended December 31, 2016 to $2.61 per Mcf for the year ended December 31, 2017. This increase in price
was primarily the result of an increase in the weighted average monthly closing NYMEX price for the current period to $3.11 per MMBtu compared to the year ended December 31, 2016 weighted
average monthly closing NYMEX price of $2.45 per MMBtu, aided by a $0.10 per MMbtu increase in the average Basis to $(0.58) per MMbtu in the current period compared to the prior period Basis of
$(0.68) 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 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 slightly to $0.71 per Mcf for the year ended December 31, 2017 as compared to $0.72 per Mcf for the year
ended December 31, 2016. Post-production costs were slightly lower than the previous year primarily because of a slightly lower electricity usage charge per Mcf during the period due to a
decline in production on the Greene County Gathering System.

Production
decreased 16% from 4,319 MMcf for the year ended December 31, 2016 to 3,618 MMcf for the year ended December 31, 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 were $1.2 million for the year ended December 31, 2017, as compared to $1.3 million for the year ended
December 31, 2016. During the year ended December 31, 2017, the decrease in expense resulted from lower professional services charges related to tax and advisory services.

For the twelve months ended December 31, 2016 compared to twelve months ended
December 31, 2015

Distributable income for the year ended December 31, 2016 decreased to $3.5 million from $5.0 million for the year ended
December 31, 2015. Compared to the year ended December 31, 2015, royalty income decreased $1.4 million and general and administrative expenses increased by $0.1 million. No
cash reserves were withheld or released by the Trustee during the years ended December 31, 2016 and 2015.

Royalty
income decreased from $6.2 million for the year ended December 31, 2015 to $4.8 million for the year ended December 31, 2016, a decrease of
$1.4 million. This decrease was due to a decrease in the average realized price, a decrease in production, and an increase in post-production costs.

The
average price realized for the year ended December 31, 2016 decreased $0.12 per Mcf to $1.13 per Mcf as compared to $1.25 for the year ended December 31, 2015. The
decrease in the average sales price for gas production was due to a slight decrease in the weighted average monthly closing NYMEX price and by higher post-production costs, offset partially by an
increase to the average Basis. The average sales price, before post-production costs, decreased from $1.91 per Mcf for the year ended December 31, 2015 to $1.85 per Mcf for the year ended
December 31, 2016. This decrease in price was primarily the result of a decrease in the weighted average monthly closing NYMEX price for the current period to $2.45 per MMBtu compared to the
year ended December 31,

48

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Table of Contents

2015
weighted average monthly closing NYMEX price of $2.64 per MMBtu, partially offset by a $0.14 per MMbtu increase in the average Basis to $(0.67) per MMbtu in the current period compared to the
prior period Basis of $(0.81) 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 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 slightly to $0.72 per Mcf for the year ended December 31, 2016 as compared to $0.66 per Mcf for the year
ended December 31, 2015. Post-production costs were higher than the previous year primarily because of (1) a higher electricity usage charge per Mcf during the period due to a decline in
production on the Greene County Gathering System and (2) higher firm transportation fees.

Production
decreased 13% from 4,973 MMcf for the year ended December 31, 2015 to 4,319 MMcf for the year ended December 31, 2016. 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 were $1.3 million for the year ended December 31, 2016, as compared to $1.2 million for the year ended
December 31, 2015. During the year ended December 31, 2016, the increase in expense resulted from an increase to the administrative fee paid to the Trustee, which was the result of the
timing of billings in the current year.

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

In
November 2017, Greylock Energy, LLC, and certain of its wholly owned subsidiaries ("Greylock") acquired substantially all of the gas production and midstream assets of Legacy
ECA, including all of Legacy ECA's interests in certain natural gas properties that are subject to royalty interests held by the Trust.

In
connection with the transaction, Greylock assumed all of Legacy ECA's obligations under the Amended and Restated Trust Agreement among the Trust, Legacy ECA and the Trustee, and other
instruments to which Legacy ECA and the Trustee are parties, including (1) the Administrative Services Agreement by and among Legacy ECA, the Trust and the Trustee dated July 7, 2010,
and (2) a letter agreement between Legacy ECA and the Trustee regarding certain loans to be made by Legacy ECA to the Trust as necessary to enable the Trust to pay its liabilities as they
become due (the "Letter Agreement"). In addition, Legacy ECA, Greylock, and the Trustee entered into a Reaffirmation and Amendment of Mortgage, Assignment of Leases, Security Agreement, Fixture Filing
and Financing Statement (the "Reaffirmation Agreement"), pursuant to which, among other things, Greylock (1) reaffirmed the liens and the security interest granted pursuant to the existing
mortgage securing the interests in the subject properties, as well as the mortgage and the obligations of Legacy ECA under the mortgage, and (2) assumed the obligations of Legacy ECA under the
Letter Agreement.

49

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Table of Contents

Legacy
ECA completed its drilling obligation to the Trust under the Development Agreement as of November 30, 2011. Consequently, no additional wells will be drilled for the Trust.
All trust units share in all cash distributions on a pro rata basis. As of December 31, 2017 the Trust owned 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 Legacy 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 Greylock's current 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 Greylock's current interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter. Approximately 50% of the originally estimated
natural gas production attributable to the Royalty Interests was hedged through March 31, 2014.

Legacy
ECA was obligated to drill all of the PUD Wells by March 31, 2014. As of November 30, 2011, Legacy 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 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 Legacy ECA for such post-production costs on the related Greene County Gathering System were limited to $0.52 per
MMBtu gathered until Legacy ECA fulfilled its drilling obligation in 2011; since then Legacy ECA was and Greylock is 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) Greylock's net revenue interest in the well. Greylock 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 Greylock owns a 100% working interest in a PUD Well, the applicable net revenue interest is calculated by multiplying Greylock'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 Greylock'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.

50

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Table of Contents

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



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. The amount of the quarterly distributions fluctuates 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.

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 Greylock 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 Greylock pursuant to the ASA. 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.

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Table of Contents

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other
arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Contractual Obligations

A summary of the Trust's contractual obligations as of December 31, 2017 is provided in the following table (in thousands):



Payments Due by Year2018

2019

2020

2021

2022

Thereafter

TotalAdministrative services fee

$
60.0

$
60.0

$
60.0

$
60.0

$
60.0

$
435.0

$
735.0Trustee administrative fee


150.0


150.0


150.0


150.0


150.0


1,087.5


1,837.5Delaware trustee fee


2.5


2.5


2.5


2.5


2.5


18.1


30.6​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​$
212.5

$
212.5

$
212.5

$
212.5

$
212.5

$
1,540.6

$
2,603.1​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
​
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​
​
​
​
​
​
​
​
​
​
​
​
​
​
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​
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​
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​
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​
​
​
​
​
​
​
​
​
​
​


Pursuant
to the terms of the ASA, the Trust is obligated to pay Greylock an annual administrative services fee of $60,000 for accounting, bookkeeping and informational services relating
to the Royalty Interests to be performed by Greylock on behalf of the Trust throughout the term of the Trust. Pursuant to the Trust Agreement, the Trustee is to be paid an annual administrative fee of
$150,000, which may be adjusted annually, up or down, by the amount of the change in the All Urban Consumers (CPI-U)US City Average for the immediately preceding calendar year, not to
exceed +/ 3% in any one year. The Trust is also obligated to pay the Delaware Trustee a fee of $2,500 per year, throughout the term of the Trust.

Greylock
and the Trustee each may terminate the provisions of the ASA relating to Greylock's provision of administrative services at any time following delivery of notice no less than
90 days prior to the date of termination; provided, however, that Greylock may not terminate the ASA except in connection with Greylock's transfer of some or all of the Subject Interests, as
defined in the Conveyances, and then only with respect to the services to be provided with respect to the Subject Interests being transferred, and only upon the delivery to the Trustee of an agreement
of the transferee of such Subject Interests reasonably satisfactory to the Trustee in which such transferee assumes the responsibility to perform the services relating to the Subject Interests being
transferred.

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 SEC 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 Interests are not burdened by field and lease operating expenses. Thus, the statement shows

52

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Table of Contents

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 Interests in gas properties are 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 Accounting Standards Codification 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. Estimates of undiscounted future net revenues attributable to proved gas reserves utilize NYMEX forward pricing curves. At December 31, 2017, 2016, and 2015, the undiscounted future
net revenues exceeded the Net royalty interest in the gas properties, and therefore no impairment was necessary in any year presented. Significant dispositions or abandonment of the Underlying
Properties, if necessary, are charged to Royalty Interests and the Trust Corpus.

Amortization
of the Royalty Interests in gas properties is calculated on a units-of-production basis, whereby the Trust's cost basis in the properties is divided by Trust total proved
reserves to derive an amortization rate per reserve unit. Such amortization does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Revisions to estimated future
units-of-production are treated on a prospective basis beginning on the date significant revisions are known.

The
conveyance of the Royalty Interests to the Trust was accounted for as a purchase transaction. The $352,100,000 reflected in the Statements of Assets, Liabilities and Trust Corpus as
Royalty Interests in Gas Properties represents 17,605,000 Trust Units valued at $20.00 per unit. The carrying value of the Trust's investment in the Royalty Interests is not necessarily indicative of
the fair value of such Royalty Interests.

Item 7A.Quantitative and Qualitative Disclosures About Market Risk

Hedge Contracts

The primary asset of and source of income to the Trust are the 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. Through March 31, 2014
the Royalty Interests were subject to the hedge contracts which were intended to reduce the Trust's exposure to natural gas price volatility. Since the expiration on March 31, 2014, of all
hedge contracts held by the Trust, the Trust has had, and will continue to have, greater exposure to market risk from the fluctuation in natural gas prices.

53

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Table of Contents

Item 8.Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm

To
the Unit Holders of ECA Marcellus Trust I and The Bank of New York Mellon Trust Company, N.A., as Trustee of ECA Marcellus Trust I

Opinion on the Financial Statements

We have audited the accompanying statements of assets, liabilities, and trust corpus of ECA Marcellus Trust I (the Trust) as of
December 31, 2017 and 2016, and the related statements of distributable income and trust corpus for each of the three years in the period ended December 31, 2017, and the related notes
(collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Trust at December 31,
2017 and 2016, and the results of its distributable income and trust corpus for each of the three years in the period ended December 31, 2017, in conformity with the modified cash basis of
accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust's financial
statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to
the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We
conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over
financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness
of the Trust's internal control over financial reporting. Accordingly, we express no such opinion.

Our
audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond
to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant
estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.



/s/ Ernst & Young LLP


We
have served as the Trust's auditor since 2010.

Pittsburgh,
Pennsylvania

March 20,
2018

54

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Table of Contents

ECA Marcellus Trust I

Statements of Assets, Liabilities, and Trust Corpus

As of December 31,



2017

2016ASSETS:Cash

$
356,602

$
426,056Royalty income receivable


1,359,959


1,421,669Royalty interest in gas properties


352,100,000


352,100,000Accumulated amortization


(301,774,826
)

(296,862,590
)​
​
​
​
​
​
​
​Net royalty interest in gas properties


50,325,174


55,237,410​
​
​
​
​
​
​
​Total Assets

$
52,041,735

$
57,085,135​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​LIABILITIES AND TRUST CORPUS:Liabilities:Distributions payable to unitholders

$
1,178,851

$
1,299,934Trust corpus; 17,605,000 common units authorized, issued and outstanding


50,862,884


55,785,201​
​
​
​
​
​
​
​Total Liabilities and Trust Corpus

$
52,041,735

$
57,085,135​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​




See notes to the audited financial statements.

55

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Table of Contents

ECA Marcellus Trust I

Statements of Distributable Income



Year Ended
December 31,
2017

Year Ended
December 31,
2016

Year Ended
December 31,
2015Royalty income

$
6,874,593

$
4,764,095

$
6,193,749​
​
​
​
​
​
​
​
​
​
​Net proceeds to Trust

$
6,874,593

$
4,764,095

$
6,193,749General and administrative expense


(1,149,266
)

(1,268,968
)

(1,195,483
)Interest income


5,976


1,020


6​
​
​
​
​
​
​
​
​
​
​Distributable income available to unitholders

$
5,731,303

$
3,478,147

$
4,998,272​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​Distributable income per common unit (17,605,000 units authorized and outstanding for 2017, 2016 and 2015)

$
0.326

$
0.198

$
0.283​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​




See notes to the audited financial statements.

56

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Table of Contents

ECA Marcellus Trust I

Statements of Trust Corpus



Year Ended
December 31,
2017

Year Ended
December 31,
2016

Year Ended
December 31,
2015Trust Corpus, Beginning of Period

$
55,785,201

$
61,507,645

$
67,631,304Distributable income


5,731,303


3,478,147


4,998,272Distributions paid or payable to unitholders


(5,741,384
)

(3,474,495
)

(4,994,156
)Amortization of royalty interest in gas properties


(4,912,236
)

(5,726,096
)

(6,127,775
)​
​
​
​
​
​
​
​
​
​
​Trust Corpus, End of Period

$
50,862,884

$
55,785,201

$
61,507,645​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​




See notes to the audited financial statements.

57

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Table of Contents



ECA MARCELLUS TRUST I

NOTES TO AUDITED FINANCIAL STATEMENTS

NOTE 1. Organization of the Trust

ECA Marcellus Trust I is a Delaware statutory trust formed in March 2010 by Energy Corporation of America ("Legacy 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", comprising approximately 9,300 acres held by Legacy ECA,
of which it owned 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 Legacy 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 Legacy 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 Legacy ECA's interest in the PUD Wells. In November 2017, Greylock Energy, LLC, and certain of its wholly owned subsidiaries ("Greylock") acquired
substantially of the assets of Legacy ECA, as described in Note 4.

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 PDP and PUD 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 Legacy ECA for such post-production costs on the Greene County Gathering System were
limited to $0.52 per MMBtu gathered until Legacy ECA fulfilled its drilling obligation (which it did in November 2011); thereafter, Legacy ECA had the right and Greylock currently has the right to
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.

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 the 60th day following the completion of each quarter. Unless sooner liquidated, the Trust will 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 Greylock. 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. Greylock will have a right
of first refusal to purchase the remaining 50% of the Royalty Interests at the termination of the Trust.

58

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Table of Contents

ECA MARCELLUS TRUST I

NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)

NOTE 1. Organization of the Trust (Continued)

The
business and affairs of the Trust are administered by The Bank of New York Mellon Trust Company, N.A. as Trustee. Although Greylock operates all of the Producing Wells and all of the
PUD
Wells, Greylock 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 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 and is therefore subject to adjustment in future periods to reflect actual production for the periods presented.

NOTE 3. Significant Accounting Policies

The accompanying audited financial information has been prepared by the Trustee in accordance with
the instructions to Form 10-K. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles in the United States
of America ("GAAP") because certain cash reserves may be established for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. Amortization of expired
floor price contract premiums does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Amortization of the investment in overriding royalty interests calculated on a
unit-of-production basis is charged directly to Trust Corpus. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities
and Exchange Commission ("SEC") 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 maturing in three months or less from the date acquired.

59

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Table of Contents

ECA MARCELLUS TRUST I

NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)

NOTE 3. Significant Accounting Policies (Continued)

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 Interests in gas properties are 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 Accounting Standards Codification 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.
Estimates of undiscounted future net revenues attributable to proved gas reserves utilize NYMEX forward pricing curves. At December 31, 2017, 2016, and 2015, the undiscounted future net
revenues exceeded the Net royalty interest in the gas properties, and therefore no impairment was necessary in any year presented. Significant dispositions or abandonment of the Underlying Properties,
if necessary, 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.

60

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Table of Contents

ECA MARCELLUS TRUST I

NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)

NOTE 4. Reaffirmation Agreement

On November 29, 2017, Greylock acquired substantially all of the gas production and midstream assets of Legacy ECA, including Legacy ECA's interests in certain natural gas
properties that are subject to royalty interests held by the Trust.

In
connection with the transaction, Greylock assumed all of Legacy ECA's obligations under the Amended and Restated Trust Agreement among the Trust, Legacy ECA and the Trustee, and other
instruments to which Legacy ECA and the Trustee are parties, including (1) the Administrative Services Agreement by and among Legacy ECA, the Trust and the Trustee dated July 7, 2010,
and (2) a letter agreement between Legacy ECA and the Trustee regarding certain loans to be made by Legacy ECA to the Trust as necessary to enable the Trust to pay its liabilities as they
become due (the "Letter Agreement"). In addition, Legacy ECA, Greylock, and the Trustee entered into a Reaffirmation and Amendment of Mortgage, Assignment of Leases, Security Agreement, Fixture Filing
and Financing Statement (the "Reaffirmation Agreement"), pursuant to which, among other things, Greylock (1) reaffirmed the liens and the security interest granted pursuant to the existing
mortgage securing the interests in the subject properties, as well as the mortgage and the obligations of Legacy ECA under the mortgage, and (2) assumed the obligations of Legacy ECA under the
Letter Agreement.

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.
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 during the years ended December 31, 2017 or 2016.

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. Although the Trust Agreement
permitted this fee to be adjusted beginning on the fifth anniversary of the Trust, the fee remained unchanged for the year ended December 31, 2017. These costs, as well as those to be paid to
Greylock pursuant to the Administrative Services Agreement referred to below, are deducted by the Trust in the period paid.

Administrative Services Fee:

The Trust and Greylock are parties to an Administrative Services Agreement that obligates the Trust to pay Greylock an administrative services
fee for accounting, bookkeeping and informational services to be performed by Greylock 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, Greylock 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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Table of Contents

ECA MARCELLUS TRUST I

NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)

NOTE 6. Related Party Transactions (Continued)

Supplemental Reserve Information (Unaudited):

Information regarding estimates of the proved natural gas reserves attributable to the Trust is based on reports prepared by independent
petroleum engineering consultants. Such estimates were prepared in accordance with guidelines established by the SEC. Accordingly, the estimates were based on existing economic and operating
conditions. Numerous uncertainties are inherent in estimating reserve volumes and values and such estimates are subject to change as additional information becomes available.

The
reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.

The
standardized measure of discounted future net cash flows was determined based on reserve estimates prepared by the independent petroleum engineering consultants, Ryder Scott
Company, L.P.

The
following table reconciles the estimated quantities of the proved natural gas reserves attributable to the Trust's interest from January 1, 2015 to December 31, 2017:



Natural Gas
(MMcf)Proved reserves:Balance at January 1, 2015


54,451​
​
​
​
​​
​
​
​
​​
​
​
​
​Revisions of previous estimates


(3,493
)Production


(4,973
)​
​
​
​
​Balance at December 31, 2015


45,985​
​
​
​
​​
​
​
​
​​
​
​
​
​Revisions of previous estimates


(979
)Production


(4,319
)​
​
​
​
​Balance at December 31, 2016


40,687​
​
​
​
​​
​
​
​
​​
​
​
​
​Revisions of previous estimates


1,108Production


(3,618
)​
​
​
​
​Balance at December 31, 2017


38,177​
​
​
​
​​
​
​
​
​​
​
​
​
​


Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized
measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC topic Extractive ActivitiesOil and
Gas. Future cash inflows were computed by applying hydrocarbon prices based on the average prices during the twelve-month period prior to the ending date of the period covered the applicable reserve
report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were

62

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Table of Contents

ECA MARCELLUS TRUST I

NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)

NOTE 6. Related Party Transactions (Continued)

defined
by contractual arrangements as required by the SEC regulations. The following is the standardized measure of discounted future net cash flows as of December 31 (in thousands):



2017

2016

2015Future cash inflows

$
100,272

$
75,015

$
88,572Future production costs


(26,342
)

(28,481
)

(31,270
)​
​
​
​
​
​
​
​
​
​
​Future net cash flows before discount


73,930


46,534


57,30210% discount to present value


(36,744
)

(22,197
)

(27,673
)​
​
​
​
​
​
​
​
​
​
​Standardized measure of discounted future net cash flows(1)

$
37,186

$
24,337

$
29,629​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​


(1)No
provision for federal or state income taxes has been provided for in the calculation because taxable income is passed through to the unitholders of the Trust.


Changes in Standardized Measure of Discounted Future Net Cash Flows:

The following schedule reconciles the changes from January 1, 2015 to December 31, 2017 in the standardized measure of discounted
future net cash flows relating to proved reserves (in thousands):



Standardized measure, January 1, 2015

$
83,720Net proceeds to the Trust


(6,194
)Revisions of previous estimates


(2,251
)Accretion of discount


8,372Net change in price and production cost


(44,193
)Other


(9,825
)​
​
​
​
​Standardized measure, December 31, 2015

$
29,629Net proceeds to the Trust


(4,746
)Revisions of previous estimates


(585
)Accretion of discount


2,963Net change in price and production cost


(1,924
)Other


(1,000
)​
​
​
​
​Standardized measure, December 31, 2016

$
24,337Net proceeds to the Trust


(6,875
)Revisions of previous estimates


1,080Accretion of discount


2,434Net change in price and production cost


13,934Other


2,276​
​
​
​
​Standardized measure, December 31, 2017

$
37,186​
​
​
​
​​
​
​
​
​​
​
​
​
​


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Table of Contents

Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A.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 (the "Exchange Act"), is recorded, processed, summarized and
reported within the time periods specified in the SEC's rules and regulations promulgated by the SEC. Disclosure controls and procedures include controls and procedures designed to ensure that
information required to be disclosed by the Trust is accumulated and communicated by Greylock 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 contractual arrangements of the Trust Agreement and the conveyances, the Trustee relies on (i) information provided by Greylock, including historical operating data,
plans for future operating and capital expenditures, reserve information and information relating to projected production, and (ii) conclusions and reports regarding reserves by the Trust's
independent reserve engineers. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 of this report, for a description of certain risks relating
to these arrangements and reliance on information when reported by Greylock to the Trustee and recorded in the Trust's results of operations.

Trustee's Report on Internal Control over Financial Reporting

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in
Rule 13a- 15(f) promulgated under the Exchange Act. The Trustee conducted an evaluation of the effectiveness of the Trust's internal control over financial reporting based on the criteria
established inInternal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (2013
Framework). Based on the Trustee's evaluation under the framework inInternal ControlIntegrated Framework, the Trustee concluded that the
Trust's internal control over financial reporting was effective as of December 31, 2017.

A
registrant's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A registrant's internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the
modified basis of accounting discussed above, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant;
and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrant's assets that could have a material effect on
the financial statements.

Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject

64

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Table of Contents

to
the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 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 December 31, 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
Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Greylock.

Item 9B.Other Information.

None.

65

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Table of Contents

PART III

Item 10.Directors, Executive Officers and Corporate Governance.

The Trust has no directors or executive officers. The Trustee is a corporate Trustee that may be removed by the affirmative vote of the holders
of not less than a majority of the outstanding Trust units at a meeting at which a quorum is present.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires officers, directors and the holders of more than 10 percent of the Trust units to file
with the SEC reports regarding their ownership and changes in ownership of the Trust units. The Trust has no officers or directors. The Trustee is not aware of any 10 percent unitholder having
failed to comply with Section 16(a) filing requirements in 2017.

Audit Committee and Nominating Committee

Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating
committee.

Code of Ethics

The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore,
has not adopted a code of ethics applicable to such persons. However, employees of the Trustee must comply with the Trustee's code of ethics.

Item 11.Executive Compensation.

During the years ended December 31, 2015, 2016 and 2017, the Trustee received administrative fees from the Trust pursuant to the Trust
Agreement. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.

Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

Based
solely on filings with the SEC, the Trustee is not aware of any holders of 5% or more of the units as of March 16, 2018.

Not
applicable.

The
registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result
in a change of control of the registrant.

Item 13.Certain Relationships, Related Transactions and Director Independence.

Administrative Services Agreement

Under the terms of the Administrative Services Agreement, the Trust pays a quarterly administration fee of $15,000 to Greylock. General and
administrative expenses in the Trust's statements of distributable income for the years ended December 31, 2017, 2016 and 2015 include

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Table of Contents

$60,000
in administrative fees for each year. Greylock and the Trustee each may terminate the provisions of the Administrative Services Agreement relating to the provision by Greylock of
administrative services at any time following delivery of notice no less than 90 days prior to the date of termination; provided, however, that Greylock may not terminate the Administrative
Services Agreement except in connection with Greylock's transfer of some or all of the Subject Interests, as defined in the Conveyances, and then only with respect to the services to be provided with
respect to the Subject Interests being transferred, and only upon the delivery to the Trustee of an agreement of the transferee of such Subject interests reasonably satisfactory to the Trustee in
which such transferee assumes the responsibility to perform the services relating to the Subject Interests being transferred.

Trustee Administrative Fee

Under the terms of the Trust Agreement, the Trust pays an annual administrative fee to the Trustee of $150,000, paid in four quarterly
installments of $37,500. The Trust also pays an annual administrative fee to the Delaware Trustee of $2,500. General and administrative expenses in the Trust's statements of distributable income for
the twelve months ended December 31, 2017, 2016 and 2015 included administrative fees of approximately $165,000, $114,000, and $150,000, respectively. Any variances from the annual fee are the
result of such fees being recorded by the Trust in the period paid rather than in the period incurred.

Director Independence

The Trust does not have a board of directors.

Item 14.Principal Accounting Fees and Services.

The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other
professional service firms and related fees are granted by the Trustee. The Trustee has appointed Ernst & Young LLP as the independent registered public accounting firm to audit the
Trust's financial statements for the fiscal year ending December 31, 2018. During fiscal 2017 and 2016, Ernst & Young LLP served as the Trust's independent registered public
accounting firm.

The
following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2017 and 2016 by Ernst & Young LLP:



2017

2016Audit fees(1)

$
150,000

$
147,500Audit-related fees





Tax fees


223,550


221,400All other fees





​
​
​
​
​
​
​
​Total fees

$
373,550

$
368,900​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​


(1)Fees
for audit services included fees for the reviews of the Trust's quarterly financial statements.


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Table of Contents

PART IV

Item 15.Exhibits and Financial Statement Schedules



The
following financial statements are set forth under "Financial Statements and Supplementary Data" in Item 8 of this report on the pages indicated:





Reports of Independent Registered Public Accounting Firm

54Statements of Assets, Liabilities and Trust Corpus as of December 31, 2017 and 2016

55Statements of Distributable Income for the Years Ended December 31, 2017, 2016 and 2015

56Statements of Trust Corpus as of December 31, 2017, 2016 and 2015

57Notes to Financial Statements

58Supplemental Reserve Information (Unaudited)

62




Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.



The exhibits below are filed or furnished herewith or incorporated herein by reference.



Exhibit
Number



Description3.1



Certificate of Trust of ECA Marcellus Trust I (Incorporated herein by reference to Exhibit 3.1 to Registration Statement on
Form S-1 (Registration No. 333-165833)).3.2



Amended and Restated Trust Agreement of ECA Marcellus Trust I, dated July 7, 2010, among Energy Corporation of America
and The Bank of New York Mellon Trust Company, N.A., as Trustee, and Corporation Trust Company, as Delaware Trustee (Incorporated herein by reference to Exhibit 3.1 to the Trust's Current Report on Form 8-K filed on July 13, 2010 (File
No. 001-34800)).23.1
*


Consent of Ernst & Young LLP23.2
*


Consent of Ryder Scott Company, L.P.31
*


Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 200232
*


Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 200299.1



Report of Ryder Scott Company, L.P. dated January 18, 2017 (included in Appendix A to this report)


*Filed
herewith.


Item 16.Form 10-K Summary

None.

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Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 IBy:

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., as TrusteeBy:

/s/ SARAH NEWELL Sarah Newell Vice President


March 20,
2018

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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Table of Contents

Appendix A

GRAPHIC

January 18,
2018

ECA
Marcellus Trust I
The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue, Suite 500
Austin, Texas 78701

Gentlemen:

At
your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain royalty interests
of ECA Marcellus Trust I (the Trust) as of December 31, 2017. The Trust was originally formed by Energy Corporation of America (ECA) to own royalty interests in natural gas properties now owned
and operated by Greylock Energy (Greylock) in the Marcellus Shale formation in Greene County, Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure
guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released
January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 18, 2018 and presented herein, was prepared for public disclosure by the Trust in
filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The properties evaluated by Ryder Scott represent 100 percent of the total net proved
reserves of the Trust as of December 31, 2017.

The
estimated reserves and future net income amounts presented in this report, as of December 31, 2017, are related to hydrocarbon prices. The hydrocarbon prices used in the
preparation of this report are based on the average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect
on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore,
volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are
summarized as follows.

SEC PARAMETERSEstimated Net Reserves and Income Data
Certain Royalty Interests of ECA Marcellus Trust I



As of December 31, 2017Total
Proved
ProducingNet Remaining ReservesGasMMcf


38,177Income DataFuture Gross Revenue

$
100,272,482Deductions


26,342,286​
​
​
​
​Future Net Income (FNI)

$
73,930,196Discounted FNI @ 10%

$
37,186,293


A-1

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Table of Contents

All
gas volumes are reported on an "as sold basis" expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of 60 degrees Fahrenheit and 14.73 psia.

The
estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic
Evaluation Software, a copyrighted program of TRC Consultants. The program was used at the request of the Trust. Ryder Scott has found this program to be generally acceptable, but notes that certain
summaries
and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash
flow projections of the same properties, also due to rounding. The rounding differences are not material.

The
future gross revenue is normally presented after the deduction of production taxes, but in the State of Pennsylvania, these are zero. Furthermore, the Trust owns only a royalty
interest, and the deductions shown as "Other" deductions in the cash flows incorporate the Trust's share of post-production costs including gathering, compression, and transportation fees. The future
net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any
adjustment for cash on hand or undistributed income. Gas reserves account for 100 percent of total future gross revenue from proved reserves.

The
discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other
discount rates which were also compounded monthly. These results are shown in summary form as follows.



Discounted Future Net Income
As of December 31, 2017Discount Rate Percent

Total
Proved5

$
49,734,5128

$
41,391,02512

$
33,732,59515

$
29,575,100


The
results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulations
Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "Petroleum Reserves Definitions" is included as an attachment to this report. The various proved
reserve status categories are defined under the attachment entitled "Petroleum Reserves Status Definitions and Guidelines" in this report.

No
attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas
consumed in operations as reserves.

Reserves
are "estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects
to known accumulations." All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the
estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and
the interpretation of

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Table of Contents

these
data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be
recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At the Trust's request, this
report addresses only the proved reserves attributable to the properties evaluated herein.

Proved
oil and gas reserves are "those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible from a given date forward." The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on
deterministic methods, as a "high degree of confidence that the quantities will be recovered."

Proved
reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states
that "as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time,
reasonably certain EUR is much more likely to increase or remain constant than to decrease." Moreover, estimates of proved reserves may be revised as a result of future operations, effects of
regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities,
and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts. Certain contractual obligations of Greylock to produce these volumes
have been incorporated into this evaluation.

Greylock's
operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating
to land tenure and leasing, the legal rights to produce hydrocarbons, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including
income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income
actually received to differ significantly from the estimated quantities.

The
estimates of proved reserves presented herein were based upon a detailed study of the properties in which the Trust owns an interest; however, we have not made any field examination
of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up
damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of
recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the
Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted
analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These
methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods
which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated
performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

A-3

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Table of Contents

In
many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate,
irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of
the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve
category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities
reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are much more likely than not to be achieved." The SEC states that
"probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." The SEC
states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low
probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates
of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore,
estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as
changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

All
of the proved reserves for the properties included herein were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis
which utilized extrapolations of historical production and pressure data available through mid-December 2017. The data utilized in this analysis were furnished to Ryder Scott by Greylock and were
considered sufficient for the purpose thereof.

To
estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of
reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of
future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing
economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the
sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with
rules adopted by the SEC, omitted from consideration in making this evaluation.

Greylock
has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.
In preparing our forecast of future proved production and income, we have relied upon data furnished by Greylock with respect to property interests owned, production and well tests from examined
wells, normal direct costs of operating the wells or leases, the Pennsylvania impact fee, other costs such as gathering and/or transportation fees, product prices based on the SEC regulations,
adjustments or differentials to product prices, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of
the data furnished by Greylock. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

A-4

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Table of Contents

In
summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures
that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and
Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the "SEC
Regulations." In our
opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

Our forecasts of future production rates for the producing properties included herein are based on historical performance data and the
established decline trend of each well. Future production rates may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related
to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the "as of
date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

Greylock
furnished us with the above mentioned average prices in effect on December 31, 2017. These initial SEC hydrocarbon prices were determined using the 12-month average
first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein.
The table below summarizes the "benchmark price" and "price reference" used for the geographic area included in the report.

The
product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions,
and/or distance from market, referred to herein as "differentials." The differentials used in the preparation of this report were furnished to us by Greylock. The differentials furnished to us were
accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Greylock to determine these differentials.

In
addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the "average realized price." The average realized
price shown in the table below was determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC
disclosure requirements for the geographic area included in the report.



Geographic Area

Product

Price
Reference

Average
Benchmark
Price

Average Realized
PriceNorth AmericaUnited States

Gas

Henry Hub

$
2.98/MMBTU

$
2.63/Mcf


The
effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

A-5

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Table of Contents

Costs

Operating costs for the leases and wells in this report were furnished by Greylock. They are based on the operating expense reports of Greylock
and include only those costs directly applicable to the leases or wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead
costs. Post-production costs, including gathering, compression, and transportation fees, are shown as "Other" deductions. The costs furnished to us were accepted as factual data and reviewed by us for
their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Greylock. No deduction was made for
loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells. All costs were held constant throughout the life of the
properties. It should be noted that the Trust only owns a royalty interest in the subject wells and is only burdened by its share of the previously mentioned post-production costs. The operating
expenses supplied by Greylock were used only to determine the economic life of each property.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world
since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent
staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as
officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This
allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder
Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many
of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating
in ongoing continuing education.

Prior
to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified
professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating
professional organization.

We
are independent petroleum engineers with respect to the Trust or Greylock. Neither we nor any of our employees have any financial interest in the subject properties and neither the
employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The
results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the
undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in
the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by the Trust.

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Table of Contents

The
Trust makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, the Trust has certain registration statements filed with the SEC under the
1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statement on
Form S-3 of the Trust of the references to our name as well as to the references to our third party report for the Trust, which appears in the December 31, 2017 annual report on
Form 10-K of the Trust. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by the Trust.

We
have provided the Trust with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in
filings made by the Trust and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The
data and work products used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.



Very truly yours,RYDER SCOTT COMPANY, L.P.TBPE Firm Registration No. F-1580\s\ Stephen E. Gardner, P.E.
Stephen E. Gardner, P.E.
Colorado License No. 44720
Senior Vice President




SEG (DCR)/pl

[Seal]


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Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott
Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner,
an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Senior Vice President responsible for ongoing reservoir evaluation studies worldwide.
Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner's geographic and job specific
experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner
earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the
States of Colorado and Texas. Mr. Gardner is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, currently serving in the latter
organization's Denver Chapter as Chairman.

In
addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education
annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2017 continuing education hours, Mr. Gardner attended the annual
Ryder Scott Reserves Conference in Houston, Texas which covered a variety of topics including well analysis and type well construction techniques, unconventional resource issues, SEC comment letter
trends, and others. At the same conference, Mr. Gardner was featured as a speaker, presenting analysis of the SCOOP/STACK plays in
Oklahoma. In addition, Mr. Gardner attended various SPEE technical seminars and internal company training during 2017 covering topics such as analysis software, statistical methods, advanced
decline analysis techniques, ethics, reserves evaluation, waterflooding, and more.

Based
on his educational background, professional training and more than 12 years of practical experience in the estimation and evaluation of petroleum reserves,
Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007.

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