UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2025 Or
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number 001-34800

ECA Marcellus Trust I

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	27-6522024 (I.R.S. Employer Identification No.)
The Bank of New York Mellon Trust Company, N.A., Trustee Global Corporate Trust 601 Travis Street, 16^th Floor Houston, 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: None

Securities registered pursuant to Section 12(g) of the Act: None

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

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 ¨ No x.

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ¨ No ¨

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

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

Smaller reporting company x

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. ¨

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ¨

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ¨

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ¨

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

The aggregate market value of Common Units representing beneficial interests in ECA Marcellus Trust I held by non-affiliates on June 30, 2025, the last business day of the registrant’s most recently completed second fiscal quarter, was $11,091,150.

As of March 24, 2026, 17,605,000 Common Units representing beneficial interests in ECA Marcellus Trust I were outstanding.

Documents Incorporated By Reference: None

TABLE OF CONTENTS

Forward-Looking Statements		2
Glossary of Certain Oil and Natural Gas Terms		3
PART I
Item 1.	Business	6
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	39
Item 1C.	Cybersecurity	39
Item 2.	Properties	41
Item 3.	Legal Proceedings	46
Item 4.	Mine Safety Disclosures	46
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	47
Item 6.	[Reserved]	47
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	48
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	52
Item 8.	Financial Statements and Supplementary Data	53
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	62
Item 9A.	Controls and Procedures	62
Item 9B.	Other Information	63
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	63
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	64
Item 11.	Executive Compensation	64
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	64
Item 13.	Certain Relationships and Related Transactions, and Director Independence	65
Item 14.	Principal Accountant Fees and Services	65
PART IV
Item 15.	Exhibit and Financial Statement Schedules	66
Item 16.	Form 10-K Summary	67
	SIGNATURES	68
Appendix A. Report of Ryder Scott Company, L.P.		A-1

References to the “Trust” in this document are to ECA Marcellus Trust I. As discussed in “ Business – “Introduction” in Item 1, in November 2017 Greylock Energy, LLC and certain of its wholly owned subsidiaries acquired substantially all of the gas production and midstream assets of Energy Corporation of America, including all of the interests of Legacy ECA (as defined below) in certain natural gas properties that are subject to the royalty interests held by the Trust (the “Acquisition”). References to “Greylock Energy” in this document are to Greylock Energy, LLC and certain of its wholly-owned subsidiaries, including Greylock Production, LLC (“Greylock Production”), which serves as operator of the subject wells, and Greylock Midstream, LLC (“Greylock Midstream”), whose subsidiaries market and gather certain of the gas. References to “Legacy ECA” in this document are to Energy Corporation of America and its wholly owned subsidiaries, and, when discussing the conveyance documents, the Private Investors (as defined in “Glossary of Certain Terms”), as such entities existed prior to the Acquisition. In this document, the “Sponsor” refers to Legacy ECA, for periods prior to the Acquisition, and to Greylock Energy, for periods after the Acquisition.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (“Form 10-K”) contains “forward-looking statements” about Greylock Energy and the Trust and other matters discussed herein that are subject to risks and uncertainties. All statements other than statements of historical fact included in this document, including, without limitation, statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” regarding the financial position, business strategy, production and reserve growth, development activities and costs and other plans and objectives for the future operations of Greylock Energy 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 Form 10-K, 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 Energy and the Trust in particular, and could cause those results to differ materially from those expressed in such forward-looking statements:

risks incident to the operation of natural gas wells;

future production costs;

the effects of existing and future laws and regulatory actions;

the effects of changes in commodity prices;

conditions in the capital markets;

the occurrence or threat of epidemic or pandemic diseases or other public health events, or any government response to such occurrence or threat;

the impact of geopolitical developments and tensions, war and uncertainty involving or in the geographical region of oil-producing countries (including the ongoing wars in Ukraine and in the Persian Gulf, and any related political or economic responses and counter-responses or otherwise by various global actors or the general effect on the global economy);

global economic conditions, such as a general slowdown in the global economy, the impact of new or additional trade barriers and tariffs, supply chain disruptions, inflationary pressures, currency fluctuations, changes in interest rates, and instability of financial institutions;

competition in the energy industry;

the uncertainty of estimates of natural gas reserves and production;

the occurrence of security incidents, including breaches of security, or other attack, destruction, alteration, corruption, or unauthorized access to the information technology systems of Greylock Energy or the Trustee or destruction, loss, alteration, corruption, or misuse or unauthorized disclosure of or access to data;

potential impacts on Greylock Energy’s business resulting from climate change, greenhouse gas regulations, and the impact of climate change related changes in the frequency and severity of weather patterns; and

other risks described under the caption “Risk Factors” in this Form 10-K.

This Form 10-K describes other important factors that could cause actual results to differ materially from expectations of Greylock Energy and the Trust, including under the caption “Risk Factors” in Item 1A. All subsequent written and oral forward-looking statements attributable to Greylock Energy or the Trust or persons acting on behalf of Greylock Energy 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 Form 10-K. Other terms are defined in the text of this Form 10-K. Certain references made to Legacy ECA reflect historical actions or operations that preceded the Acquisition.

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. The drilling obligation has been satisfied and the Trust has no future well locations nor drilling opportunities under the AMI or otherwise.

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.

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.

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 Sponsor’s interests in the Producing Wells (after deducting post-production costs and any applicable taxes).

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 the Sponsor’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 on July 1, 2010 with the SEC pursuant to Rule 424(b) under the Securities Act of 1933, as amended, 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.

Sponsor’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 Production from Legacy ECA as part of the asset acquisition as described in Item 1—Business—“Introduction” below.

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

Subject Interest—means Greylock Production’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 which undivided interests Greylock Production 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 the Sponsor’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 the Sponsor’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.

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 subsequently amended and restated, the “Trust Agreement”) among Energy Corporation of America, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”). The Trust maintains its offices at the office of the Trustee, at 601 Travis Street, 16^th 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 Energy”), including Greylock Production, LLC (“Greylock Production”), which serves as operator of the subject wells, and Greylock Midstream, LLC (“Greylock Midstream”), whose subsidiaries market and gather certain of the gas, 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 the Royalty Interests (described below) (the “Acquisition”).

In connection with the Acquisition, Greylock Production assumed all of Legacy ECA’s obligations under the Trust Agreement and other instruments to which Legacy ECA and the Trustee were parties at the time of the transaction, 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 Production, 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 Production (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 on its website at https://ect.q4web.com/home/default.aspx. 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, 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.

As discussed below, Legacy ECA completed its drilling obligation to the Trust under the Development Agreement as of November 30, 2011, over two years ahead 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, 2025 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 the Sponsor’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 the Sponsor’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 development w ells (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 the Sponsor 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, the Sponsor has been permitted to increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System (“GCGS”).

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 Production’s net revenue interest in the well. Greylock Production on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the Trust was 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 Greylock Production owns a 100% working interest in a PUD Well, the applicable net revenue interest is calculated by multiplying Greylock Production’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 Production’s working interest in a PUD Well is less than 100%, the Trust’s share of proceeds would be proportionately reduced.

Unless sooner terminated, as discussed in detail below under the caption “—Duration of the Trust; Sale of Royalty Interests,” the Trust will begin to liquidate on or about March 31, 2030 (the “Termination Date”). The Term Royalty Interests will revert automatically to Greylock Production at the Termination Date, and the Perpetual Royalty Interests will be sold pursuant to a marketing process expected to commence soon thereafter, with any net proceeds from the sale to be distributed pro rata to the Trust unitholders. Greylock Production has a right of first refusal to purchase the Perpetual Royalty Interests being sold by the Trust following the termination of the Trust. See “—Greylock Production’s Right of First Refusal” below.

As described below under “—Duration of the Trust; Sale of Royalty Interests,” 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, 2025 were $3.8 million. The gross proceeds attributable to the Royalty Interests are dependent upon, among other factors, the volume of hydrocarbons extracted and sold from the Underlying Properties and the price realized on those sales. The Trust has no control or influence over the volumes sold or the proceeds realized from those sales.

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 60^th day following the completion of each quarter.

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

natural gas prices received;

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

post-production costs and any applicable taxes; and

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

The 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 Section 1446 of the Internal Revenue Code of 1986 (the “IRC”), withholding tax on income effectively connected to a United States trade or business allocated to non-U.S. persons (“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 non-U.S. persons should be made at a 30% rate unless the rate is reduced by treaty. Nominees and brokers should withhold at the highest marginal rate on the distribution made to non-U.S. persons. A non-U.S. holder’s gain on the sale of Trust units is treated 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. A transferee of units is also required to withhold 10% of the amount realized on the sale or exchange of units (generally, the purchase price) unless the transferor certifies that it is not a nonresident alien individual or foreign corporation or other exception is available.

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 received by 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 Trust 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 Production, which assumed Legacy ECA’s obligations under the ASA subsequent to the Acquisition. The ASA obligates the Trust to pay Greylock Production an administrative services fee for accounting, bookkeeping and informational services to be performed by Greylock Production 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 Production 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 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.

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 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.

The Sponsor 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 Production 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 Production 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 Production receives for natural gas production attributable to the Sponsor’s retained interest.

Greylock Midstream markets the majority of its operated production and markets all of the natural gas produced from the Underlying Properties. Greylock Midstream 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 Midstream on the GCGS 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 the Sponsor’s costs to gather, compress, transport, process, treat, dehydrate and market the gas. The Sponsor is permitted to increase this fee to the extent necessary to recover certain capital expenditures on the GCGS 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 Midstream’s deductions for these post-production services.

Greylock Midstream 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 per Mcf, the purchaser of the natural gas may deduct such costs prior to making payment to Greylock Production for such production. At other times, Greylock Midstream will make payments directly to the third parties providing such post-production services. In either instance, the Trust’s cash available for distribution will be reduced by the costs paid by Greylock Midstream 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 $0.67 per MMBtu and $0.61 per MMBtu for the years ended December 31, 2025 and 2024, 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 Production 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.

The Sponsor and Columbia Gas Transmission, LLC (“Columbia”) are parties to a transportation agreement (the “Transportation Agreement”), in effect since August 1, 2011, that provides for firm transportation downstream of the GCGS at Columbia’s filed tariff rate. During the third quarter of 2024, Greylock Production and Columbia amended the Transportation Agreement to reduce the firm transportation amount, from 45,000 MMBtu that had initially prevailed under the agreement, to 39,901 MMBtu per day effective January 1, 2025 through December 31, 2027.

The tariff rates under the Transportation Agreement that had been in effect from December 1, 2021 through March 31, 2025 were set in 2022 pursuant to a settlement between Columbia and certain shippers in proceedings before the Federal Energy Regulatory Commission (“FERC”), and had been approximately $0.35 per MMBtu at one hundred percent load factor from April 2024 through March 31, 2025. On September 30, 2024, Columbia submitted an application to FERC to increase certain tariff rates effective April 1, 2025. On October 31, 2024, FERC issued an Order Accepting and Suspending the Filing, Subject to Refund. As filed, the tariff rate increased from approximately $0.35 per MMBtu to approximately $0.725 per MMBtu on the applicable contracts. Columbia began charging the increased transportation rates effective April 1, 2025. Greylock Production and other parties protested the new proposed tariff rate at FERC. On July 1, 2025, Columbia moved to place the Period I Settlement Rates into effect as of June 1, 2025 and apply such rates to the settling parties, including Greylock Production. The Chief Administrative Law Judge granted Columbia’s motion. Columbia invoiced Greylock Production at the one hundred percent load factor tariff rate of $0.4436 per MMBtu for June 2025. On August 13, 2025, Columbia filed a proposed final settlement at FERC. On September 15, 2025, the Presiding Administrative Law Judge certified the settlement as uncontested with a tariff rate of $0.4376 per MMBtu from April 1, 2025 to March 31, 2026 and increasing by $0.0075 per MMBtu annually (through March 31, 2028). FERC approved the settlement on October 30, 2025. Columbia issued refunds on the difference between the initial increased rates charged for April and May 2025 and the final settlement rate. Greylock Production will distribute to the Trust the portion of the refund attributable to the Trust, along with the proceeds attributable to the fourth quarter of 2025, during the first quarter of 2026.

Firm transportation utilized as to the Trust’s interests is a chargeable post-production cost, and the Trust bears its proportionate share of such costs; however, the Trust was not charged for the costs associated with modifying the Transportation Agreement with Columbia.

Greylock Production 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. Accordingly, to the extent that the cost of any new gas supply arrangements exceeds the cost under existing arrangements, proceeds to the Trust could decline and any such decline could be material.

Competition and Markets

The natural gas industry is highly competitive. Greylock Production 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 Production, 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 Production 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 royalty income to the Trust. In view of the many uncertainties that affect the supply and demand for natural gas, neither the Trust nor Greylock Production 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 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 Production 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 exploration, development and production operations of Greylock Production are subject to 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, released or emitted 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 Production’s operations or attributable to former operations; and impose obligations to reclaim and abandon well sites, impoundments and pits. 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. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, or the issuance of orders enjoining some or all of Greylock Production’s operations.

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 Production’s capital expenditures, results of operations and financial position. Greylock Production 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 Production’s operations, and Greylock Production 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 Production 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 Production’s capital expenditures, results of operations or financial position, Greylock Production 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 Production’s business operations are subject and for which compliance may have a material adverse impact on Greylock Production’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 U.S. Environmental Protection Agency (“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. Although petroleum, natural gas, and natural gas liquids are excluded from the definition of “hazardous substance” under CERCLA, Greylock Production handles materials in the course of Greylock Production’s operations that may be regulated as CERCLA hazardous substances, despite the so-called “petroleum exclusion.”

Greylock Production 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 Production generates petroleum hydrocarbon wastes and ordinary industrial wastes that may be classified as hazardous wastes under RCRA and comparable state laws. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, production, and development of crude oil or natural gas are currently regulated under RCRA as non-hazardous wastes. While many exploration and production wastes are exempt from regulation as hazardous waste, these wastes are generally subject to non-hazardous waste regulation under RCRA and applicable state regulations. Many state governments have specific regulations and guidance for exploration and production wastes, including the wastes associated with hydraulic fracturing activities.

Greylock Production 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 Production 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 Production 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 Production’s control. These properties and wastes disposed thereon may give rise to liability under CERCLA, RCRA and analogous state laws. Under these laws, Greylock Production 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 (“CAA”), 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 Production to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, and to comply with stringent air permit or regulatory requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of Greylock Production’s properties.

The EPA has established pollution control standards for oil and gas sources under the CAA. In 2012 and 2016, the EPA adopted federal New Source Performance Standards (“NSPS”) that require the reduction of volatile organic compound and sulfur dioxide emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific requirements regarding emissions from production-related wet seal and reciprocating compressors, pumps, and from pneumatic controllers and storage vessels, and for equipment leaks. These NSPS apply to sources that are newly constructed or modified after the rules’ applicability dates. More recently, the EPA adopted a final rule in 2024 that will directly regulate volatile organic compound and methane emissions from oil and gas sources constructed or modified after December 2022 and will require reductions in both pollutants through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. Additionally, the EPA for the first time adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.

The results of the 2024 presidential election and President Trump’s energy agenda prioritizing domestic oil and gas production will likely impact the air quality-related requirements that apply to Greylock Production. In March 2025, the EPA announced it was reconsidering the 2024 rules that established new volatile organic compound and methane emissions standards for both new and existing sources. Following that announcement, the EPA adopted amendments to the NSPS and existing source performance standards that extended the compliance deadlines for many of the new source requirements adopted in 2024 and extended the state plan submittal deadlines, which will effectively extend the dates by which existing sources must come into compliance with the existing source emissions guidelines. It is currently unknown whether EPA’s reconsideration of the 2024 rules will result in further changes. Similar to prior changes to the air pollution control standards for oil and gas sources, the most recent changes will be subject to judicial review, as well as the potential for future presidential administrations to take a different approach.

The EPA is also charged with establishing National Ambient Air Quality Standards (“NAAQS”), the implementation of which can indirectly impact Greylock Production’s operations. The CAA directs the EPA to review each NAAQS every five years to ensure that the standards are protective of public health and welfare. This process routinely results in the tightening of those standards, and in October 2015, the EPA lowered the ozone NAAQS from 75 to 70 parts per billion. In December 2020, the EPA published a final rule that retained without revision the 2015 NAAQS ozone standard. Likewise, in March 2024, the EPA issued a final rule that lowered the annual standard for fine particulate matter from 12 to 9 micrograms per cubic meter. In March 2025, however, the EPA announced that it would reconsider the rule lowering the fine particulate matter standard, and the EPA has filed a request that the U.S. Court of Appeals vacate the 2024 rule. In 2026, the EPA also has delayed taking certain actions necessary to implement air quality requirements under the lower 2024 standard. No regulatory action or court decision has changed the 2024 rule lowering the fine particulate matter standard, and the EPA’s delayed implementation of the 2024 standard likely will be subject to judicial review. State or federal implementation of the NAAQS could result in stricter permitting or regulatory requirements, delay or prohibit Greylock Production’s ability to obtain such permits, and result in increased expenditures for pollution control equipment.

Greylock Production may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. Greylock Production currently does not expect that such requirements will have a material adverse effect on its operations.

Climate Change. The Trump Administration’s efforts to roll back federal regulation of greenhouse gases (“GHGs”) represent a significant shift in federal climate policy, though the ultimate impact of those efforts on Greylock Production is unclear. In 2009, the EPA found that emissions of carbon dioxide, methane and GHGs may present an endangerment to public health and the environment and subsequently issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed oil and gas sources — as well as the EPA’s methane emissions guidelines for existing oil and gas sources that were adopted in 2024. The EPA also has adopted rules requiring the reporting of GHG emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. Shortly after President Trump took office in January 2025, the federal government embarked on a series of changes relating to climate policy and regulation. On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement. In July 2025, the EPA issued a proposed rule to rescind the 2009 GHG endangerment finding that provided a basis for GHG regulation under the CAA. In September 2025, the EPA proposed to rescind the GHG reporting program for sectors other than the oil and gas sector, while proposing to suspend GHG reporting requirements for the oil and gas sector until 2034. In February 2026, the EPA adopted a final rule repealing its prior endangerment finding, which opens the door for the EPA to repeal its GHG rules for the oil and gas sector.

The EPA has established methane standards for oil and gas sources based on the now-repealed GHG endangerment finding. In 2024, the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from new oil and gas sources and will require reductions in methane and volatile organic compound emissions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates arriving in 2029. In 2025, however, the EPA extended certain compliance deadlines for both new and existing sources, and the 2026 endangerment finding repeal provides a basis for undoing the oil and gas methane standards – though the fact that the oil and gas standards address both methane and volatile organic compounds, which are regulated independently of the EPA’s authority to regulate GHGs, may limit the impact of future changes to the methane standards that currently apply to oil and gas sources.

The Inflation Reduction Act of 2022 (the “IRA”) included new Clean Air Act section 136(c) directing the EPA to collect the Waste Emissions Charge (“WEC”) from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions, and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with the EPA’s new or existing source methane requirements. The EPA adopted new rules to implement the WEC program in November 2024; however, the fate of the WEC and the EPA rules implementing the WEC is unclear. In March 2025, President Trump signed legislation repealing the EPA’s 2024 WEC rules under the Congressional Review Act. The repeal of the EPA’s WEC rules did not eliminate the statutory requirement to pay the WEC, but it eliminated the rules established by the EPA to determine the WEC due, the payment mechanism, and any payment deadlines. The U.S. Congress may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.

Meanwhile, 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 to date have 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. For example, the states of Colorado and New Mexico have adopted rules regulating GHGs from the oil and gas industry that are based on the federal standards. Congress may in the future consider adopting other legislation to reduce emissions of greenhouse gases. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on Greylock Production’s business, capital expenditures, financial condition and results of operations.

The adoption and implementation of regulations imposing reporting obligations on, or limiting emissions of GHGs from, Greylock Production’s equipment and operations could require Greylock Production 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 Production’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 Production’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 Production’s products may become less desirable in the market with more stringent limitations on greenhouse gas emissions. Greylock Production cannot predict with any certainty at this time how these possibilities may affect its operations.

Finally, some scientists have theorized 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 significant physical effects were to occur, they could have an adverse effect on Greylock Production’s assets and operations and cause Greylock Production to incur costs in preparing for and responding to them. Additionally, energy needs could increase or decrease as a result of extreme weather conditions, depending on the duration and magnitude of those conditions.

Water Discharges. The federal Clean Water Act (“CWA”) and analogous state laws, such as the Pennsylvania Clean Streams Law, impose restrictions and strict controls on the discharge of pollutants into “waters of the United States” and waters within the scope of the state law, respectively. Pursuant to the CWA and applicable state laws, permits must be obtained to discharge pollutants into regulated waters. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the applicable state agency or both. The PADEP is authorized by the EPA to issue National Pollutant Discharge Elimination System (“NPDES”) permits for direct discharges to surface “waters of the Commonwealth” as defined in Article 1 of the Pennsylvania Clean Streams Law. The discharge of wastewater from most onshore oil and gas exploration and production activities is currently prohibited east of the 98^th meridian, an area that includes the State of Pennsylvania. Additionally, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending certain wastewater directly to publicly owned treatment works (“POTW”). Unconventional extraction facilities are allowed by 40 CFR Part 437 to send wastewater to an off-site private centralized wastewater treatment (“CWT”) facility in most circumstances. CWT facilities can either discharge treated water directly to surface waters or send it to a POTW. In 2018, the EPA concluded a study of the treatment and discharge of oil and gas wastewater that could lead to changes in requirements for discharge of produced water under Part 437, including more stringent requirements or a prohibition on discharge of produced water from CWT facilities. Additionally, in 2010 the PADEP adopted a permitting policy concerning surface water discharges from CWT 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. Any restriction of disposal options for hydraulic fracturing waste and other changes to CWA discharge requirements may result in increased costs.

The discharge of dredge and fill material in waters of the United States, including wetlands, is also prohibited unless authorized by a permit issued under CWA Section 404 by the U.S. Army Corps of Engineers (“USACE”). CWA Section 401 provides that the applicant for a Section 404 USACE permit for the discharge of dredge and fill material must seek a Section 401 water quality certification by applying to the state in which the discharge will occur for the state to determine if the discharge will comply with the state’s approved water quality program. In some instances, this process could result in a delay in issuance of the permit, more stringent permit requirements, or denial of the permit.

How the EPA and the USACE define “waters of the United States” (“WOTUS”), which defines the extent of geographic jurisdiction under the CWA, has been the subject of controversy and litigation for decades and can impact Greylock Production’s regulatory and permitting obligations under the CWA. In 2023, in Sackett v. EPA, the Supreme Court issued a landmark decision interpreting WOTUS more narrowly than the then-current definition contemplated, resulting in diminished jurisdiction over wetlands and streams that lacked certain connections to other waters or consistent water flow. Following Sackett, because of ongoing litigation, the regulatory landscape currently remains unsettled. The regulations currently in effect in 24 states define WOTUS using a 2023 regulation modified after the Sackett decision. In the rest of the country, the agencies base jurisdiction on an earlier WOTUS definition as implemented in light of a number of Supreme Court decisions, including Sackett. Despite the two approaches, jurisdiction over WOTUS is essentially consistent across the United States.

In November 2025, the Army Corps of Engineers released a proposed rule revising the regulatory definition of WOTUS. That new definition is expected to go into effect in early 2026 without substantial changes from the proposed definition. Regardless of the ultimate details, the revised definition likely will further reduce CWA jurisdiction, especially over wetlands and streams, leading to fewer permitting requirements. Once the new WOTUS definition is final, litigation will likely continue challenging the legality of the definition. This litigation could have the effect of delaying or precluding implementation of the new rule. Greylock Production’s regulatory obligations and permitting costs will continue to be subject to remaining uncertainty around the definition of WOTUS and the scope of CWA regulation, given the ongoing litigation.

USACE Nationwide Permits (“NWPs”) are a streamlined form of permitting used to authorize activities related to development activities with minimal individual or cumulative adverse effects in wetlands or other waters of the United States under the CWA. Some NWPs are also used to authorize activities that impact traditional navigable waters under the Rivers and Harbors Act. NWP 12 will expire in March 2026 and be replaced with a new version. The NWPs expire in March 2026 and will be replaced, simultaneously, with new versions that are largely unchanged from the previous set. Litigation challenging the NWPs, if filed, could result in additional cost and time for permitting projects.

In February 2025, the USACE began implementing emergency permitting procedures as directed by President Trump’s Executive Order Declaring a National Energy Emergency. This has resulted, in many instances, in substantially decreased timeframes for receiving Section 404 permits in the case of energy projects subject to the Executive Order.

Finally, the Oil Pollution Act of 1990 (“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of the United States. The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from onshore production facilities. Measures under the OPA and/or the CWA include inspection and maintenance programs to minimize spills from oil storage and conveyance systems; the use of secondary containment systems to prevent spills from reaching nearby waterbodies; proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill; and the development and implementation of spill prevention, control and countermeasure (“SPCC”) plans to prevent and respond to oil spills. The OPA also subjects owners and operators of facilities in certain instances to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill. Greylock Production has developed and implemented SPCC plans for the Underlying Properties as required under the CWA.

Endangered Species Act. The federal Endangered Species Act, as amended (“ESA”), prohibits taking of listed endangered, and in some cases threatened, species. Under the ESA, federal agencies are obligated to consult with the U.S. Fish and Wildlife Service or National Marine Fisheries Service (the “Services”) if an agency’s actions, including permit actions, may affect listed species or designated critical habitat. If endangered species are located in areas of the Underlying Properties where seismic surveys, development activities or abandonment operations may be conducted, the work could be prohibited or delayed or expensive mitigation may be required, depending on the implications for protected species and designated critical habitat. Changes to implementing rules in the Biden Administration may, in some instances, make a federal review process occasioned by the application for permits, rights of way, or leases more complex in certain circumstances. In addition, designation of new species as threatened or endangered could cause Greylock Production to incur additional costs arising from species protection measures, could result in limitations on activities, and could require a more complex regulatory compliance process. However, in 2025, the Services issued proposed revisions to the regulations implementing the ESA Section 7 consultation process and the scope of the definition of the term “take.” These regulations, if finalized, generally would be deregulatory in nature, modestly reducing the coverage of the ESA and streamlining the ESA section 7 consultation process. Nevertheless, these rules are expected to be immediately challenged in litigation, which will create uncertainty as to if and when these rules will go into effect. In January 2025, the Trump Administration directed the use of the emergency consultation procedures for permitting for energy projects in the Declaring a National Energy Emergency Executive Order.

National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires the federal government to undertake an environmental review prior to making a decision on most proposed federal actions — such as permits, leases, and rights-of-way. Driven by court decisions and Administration policy, NEPA implementation and resulting litigation changed dramatically in 2025. Key changes are driving agencies narrow their NEPA reviews and complete them faster and are driving courts to show more deference to agencies when reviewing the adequacy of an agency’s analysis under NEPA, benefitting private projects that may require federal permits and reviews.

In particular, until 2025, agencies undertook NEPA reviews pursuant to binding regulations issued by the White House Council on Environmental Quality (“CEQ”) as well as pursuant to the federal agency’s own NEPA procedures. After two federal courts found that CEQ did not have authority to issue binding regulations, CEQ withdrew their regulations. In their place, agencies each issued their own NEPA procedures and, for the most part, put those procedures in agency guidance rather than binding regulations, although the USACE (which issues permits that can be critical to construction) regulatory program is a notable exception, keeping its NEPA procedures in regulations. While the agency procedures were based on a CEQ template, there are inconsistencies among the agencies on various topics, including the requirement for public comment and consideration of various types of impacts. These procedures make changes that are intended to streamline reviews.

Also, on May 29, 2025, the Supreme Court decided Seven County Infrastructure Coalition v. Eagle County, Colorado, in which the Court expressed clear intention that NEPA should be brought “back in line with the statutory text and common sense.” Significantly for permits that may be needed for private projects, the Court clarified that agencies need only evaluate the effects of the specific “proposed action” before them, not the impacts of “other future or geographically separate projects that may be built (or extended) as a result of or in the wake of the immediate project under consideration.” The Court also emphasized that courts must afford agencies substantial deference in reviewing agency actions under NEPA and that agencies “must have broad latitude to draw a ‘manageable line’” when determining the appropriate scope of analysis. The Court’s decision may reduce litigation risk and help streamline federal reviews.

Employee Health and Safety. The operations of Greylock Production 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 in certain circumstances that information be maintained concerning hazardous materials used or produced in Greylock Production’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 applicable to the development and operation of both conventional and 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 Production 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 Production’s wells and to limit the number of wells or locations Greylock Production can drill.

Greylock Production 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 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, 2025 and 2024, with respect to the Underlying Properties.

Non-Governmental Organization Litigation. Project opponents actively file litigation challenging federal permits, rights-of-ways, leases and other authorizations related to oil and gas development activities. There has been active litigation related to such activities related to development of the Marcellus Shale. Litigation challenging federal or state authorizations needed for private development can result in the temporary or permanent loss of those authorizations with a resulting adverse impact to Greylock Production’s operations.

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 Trust 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 Production metering systems) and market prices for such volumes. Greylock Production 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 Production to the Trust with respect to a calendar quarter and the actual cash production payments relative to the Trust properties received by Greylock Production will be netted to or against future payments by Greylock Production 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 Internal Revenue Service (“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.

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 Trust unitholders, in which case the Trust unitholders calling such meeting will be responsible for all such costs. Meetings must be held in such location as the Trustee designates 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 holding a majority of Trust units outstanding must be present in person or represented by proxy to have a quorum. Each Trust unitholder is entitled to one vote for each Trust unit owned.

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

dissolve the Trust (except in accordance with its terms);

remove the Trustee or the Delaware Trustee;

amend the Trust Agreement, the royalty interest conveyances, the Administrative Services Agreement and the Royalty Interest Lien (except with respect to certain matters that do not adversely affect the right of Trust unitholders in any material respect);

merge or consolidate the Trust with or into another entity; or

approve the sale of all or any material part of the assets of the Trust,

except that if any of the matters listed above (except removal of the Trustee or the Delaware Trustee) would result in a materially disproportionate benefit to Greylock Production or its affiliates compared to other owners of Trust units (to the extent that Greylock Production or any of its affiliates were to own any Trust units at that time), the affirmative vote of the holders of a majority of Trust units, excluding Trust units owned by Greylock Production and its affiliates, 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 Production 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 among Legacy ECA, the Trustee and the Delaware Trustee. Greylock Production has assumed Legacy ECA’s obligations under the Trust Agreement as 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 Production 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:

collecting cash attributable to the Royalty Interests;

paying expenses, charges and obligations of the Trust from the Trust’s assets;

making cash distributions to the Trust unitholders;

causing to be prepared and distributed a Schedule K-1 for each Trust unitholder and preparing and filing tax returns on behalf of the Trust; and

causing to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the Trust units are listed or admitted to trading.

If a Trust liability is contingent or uncertain in amount or not yet currently due and payable, the Trustee may create a cash reserve to pay for the liability. If the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust’s liability, the Trust may borrow funds required to pay the liabilities. The Trust may borrow the funds from any person, including the Trustee or its affiliates. If the entity serving as Trustee or Delaware Trustee were to loan funds to the Trust, the terms of such indebtedness would be similar to the terms that such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity would 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, 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, at which time it will begin to liquidate. The Trust will dissolve and commence winding up its business and affairs prior to the Termination Date if:

the Trust sells all of the Royalty Interests;

gross proceeds attributable to the Royalty Interests over any four consecutive quarters are less than $1.5 million;

the holders of a majority of the outstanding Trust units vote in favor of dissolution; or

the Trust is judicially dissolved.

Following the earlier of the Termination Date or any of the foregoing dissolution triggering events, the Trustee would sell all of the Trust’s assets, either by private sale or public auction (in accordance with the procedures described below under “—Greylock Production’s Right of First Refusal”), and distribute the net proceeds of the sale to the Trust unitholders.

Greylock Production’s Right of First Refusal

Greylock Production 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 Production, prior to selling all or part of the Perpetual Royalty Interests, it will be required to give notice (the “Offer Notice”) to Greylock Production, identifying the proposed purchaser and setting forth the proposed sale price, payment terms and other material terms of the proposed sale. Greylock Production 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 Production 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 Production and the Trust would share equally the cost of reimbursement to the proposed purchaser.

If Greylock Production 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 Production, then, as a condition to the sale, Greylock Production 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 Production to the Trust for the properties is fair to the Trust.

Federal Income Tax Considerations

The Trust’s United States 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 Legacy ECA and the Trust rendered in connection with the initial public offering of the Trust units, in which counsel opined that at least 90% of the Trust’s gross income will be qualifying income within the meaning of IRC Section 7704. The Trust’s United States federal income tax reporting positions are consistent with the Federal Income Tax Considerations section in the Prospectus (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 Units, the Trust has not requested a ruling from the IRS regarding its federal income tax reporting positions and its positions may not be sustained by a court 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

The risk factors summarized and detailed below could materially harm production from the Underlying Properties, operating results and/or the Trust’s financial condition, adversely affect proceeds to the Trust and cash distributions to Trust unitholders, and/or cause the price of the Trust units to decline. These are not all of the risks the Trust faces, and other factors not presently known to the Trust or that the Trust currently believes are immaterial may also affect the Trust if they occur.

Summary of Risk Factors

The following is a summary of some of the risks and uncertainties that could materially affect the Trust’s business, financial condition and results of operations. You should read this summary together with the more detailed description of each risk factor contained below.

Operating Risks

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

Any limitation in the availability of gathering, transportation and processing facilities could interfere with sales of natural gas production from the Underlying Properties.

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 Trust unitholders.

Natural gas wells are subject to operational hazards that can cause substantial losses.

Financial Risks

Declines in the financial position of Greylock Production could impede the operation of wells.

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

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.

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 Trust has established a cash reserve for contingent liabilities and to pay expenses in accordance with the Trust Agreement, which would reduce proceeds payable to the Trust and distributions to Trust unitholders.

An increase in the negative basis differential between the price realized by Greylock Production 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 the Trust units.

The Trust has no hedges in place to protect against the price risk inherent in holding interest in natural gas.

The ability of Greylock Production to satisfy its obligations to the Trust depends on the financial position of Greylock Production.

Risks Related to the Structure of the Trust

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

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

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.

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

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

Financial information of the Trust is not prepared in accordance with GAAP.

The Trust is a smaller reporting company and benefits from certain reduced governance and disclosure requirements, which could make the Trust Units less attractive to investors.

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

Risks Related to Ownership of the Trust Units

Because the Trust units are traded on the OTC market, Trust unitholders may have more difficulty selling Trust units or obtaining accurate quotations of the Trust units.

The Private Investors may sell additional Trust units, which could adversely affect the trading price of the Trust units.

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

Legal, Environmental and Regulatory Risks

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

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 Production produces while the physical effects of climate change could disrupt Greylock Production’s production and cause Greylock Production to incur significant costs in preparing for or responding to those effects.

Cybersecurity Risks

Cyber-attacks or other failures in telecommunications or information technology systems could result in information theft, data corruption and significant disruption of Greylock Energy’s or the Trustee’s business operations.

Tax Risks

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

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 Trust unitholders would be reduced.

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

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

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.

Each Trust unitholder is required to pay taxes on the Trust unitholder’s share of the Trust’s income even if a Trust unitholder does not receive any cash distributions from the Trust.

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

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

The IRS may challenge the Trust’s treatment of each purchaser of Trust units as having the same economic attributes without regard to the actual Trust units purchased.

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.

The IRS may challenge the Trust’s adoption of certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the Trust unitholders.

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

Operating Risks

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 Production. These factors include, among others:

weather conditions and seasonal trends;

regional, domestic and foreign supply and perceptions of supply of natural gas;

the level of liquefied natural gas, or LNG, exports;

the level of demand and perceptions of demand for natural gas;

anticipated future prices of natural gas, LNG and other commodities;

technological advances affecting energy consumption and energy supply;

U.S. and worldwide political and economic conditions;

tax, trade and tariff policies of the United States and other countries involved in global energy markets;

the impact of geopolitical developments and tensions, war and uncertainty involving or in the geographical region of oil-producing countries (including the ongoing wars in Ukraine and the Persian Gulf, and any related political or economic responses and counter-responses or otherwise by various global actors or the general effect on the global economy);

the occurrence or threat of epidemic or pandemic diseases or other public health event, or any government response to such occurrence or threat;

the development, exploitation and market acceptance of alternative energy sources as part of a transition to a lower-carbon economy;

the proximity, capacity, cost and availability of gathering and transportation facilities;

the volatility and uncertainty of regional pricing differentials;

acts of force majeure;

governmental regulations and taxation; and

energy conservation and environmental measures.

A substantial or extended decline in natural gas prices will reduce profits to which the Trust is entitled and therefore the amount of cash available for distribution to Trust unitholders. For example, there were no distributions to unitholders for the quarter ended June 30, 2024, as Trust expenses exceeded net royalty income to the Trust. A prolonged period of low natural gas prices 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, or 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 Production 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 Production would have no obligation to drill a replacement well. In making such decisions, Greylock Production 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 royalty income are based on estimates of reserve quantities and royalty income 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 royalty income from the Underlying Properties could vary negatively and in material amounts from estimates and those variations could be material. Petroleum engineers are required to make subjective estimates of underground accumulations of natural gas based on factors and assumptions that include:

historical production from the area compared with production rates from other producing areas;

natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and capital expenditures;

the availability of enhanced recovery techniques;

relationships with landowners, operators, pipeline companies and others; and

the assumed effect of governmental regulation.

Changes in these assumptions or actual production costs incurred and results of actual development and production costs could materially decrease reserve estimates. In addition, the quantities of recovered reserves attributable to the Underlying Properties may decrease in the future as a result of future declines in the price of natural gas.

The generation of proceeds for distribution by the Trust depends in part on gathering, transportation and processing facilities owned by Greylock Midstream 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 Production is provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If Greylock Production is forced to reduce production due to such a curtailment, the royalty income 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 Production 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 GCGS, including natural gas produced from the Underlying Properties, is currently shipped on two interstate natural gas transportation pipelines. Greylock Production 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 Production and Columbia Gas Transmission, LLC are parties to an agreement relating to firm transportation downstream of the GCGS for 45,000 MMBtu through December 31, 2024 and 39,901 MMBtu though December 31, 2027 as described under “Business—Marketing and Post-Production Services” in Item 1 of this Form 10-K. Firm transportation utilized as to the Trust’s interests is a chargeable post-production cost, and the Trust bears its proportionate share of such costs. In the future, Greylock Production may seek to obtain additional firm transportation capacity, but such capacity may not be available. In addition, to the extent Greylock Production’s customers or Greylock Production 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 Production 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 Production or its customers to procure sufficient capacity to transport the natural gas gathered on the GCGS 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 Production for production attributable to the Royalty Interests will reduce the proceeds received by the Trust and, accordingly, cash distributions to Trust unitholders.

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

Natural gas wells are subject to operational hazards that can cause substantial losses. Greylock Production 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 distributions to Trust unitholders by reducing the amount of proceeds available for distribution.

Additionally, if any of such risks or similar accidents occur, Greylock Production 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 Production experiences any of these problems, its ability to conduct operations and perform its obligations to the Trust could be adversely affected. Greylock Production’s operations may result in liabilities exceeding its insurance coverage or liabilities not covered by insurance. If a well is damaged, Greylock Production 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.

Financial Risks

Declines in the financial position or creditworthiness of Greylock Production or any third-party operators could impede the operation of wells.

The value of the Royalty Interests and the Trust’s ultimate cash available for distribution is highly dependent on the financial condition of Greylock Production. The ability of Greylock Production or any third-party operator to operate the Underlying Properties depends on Greylock Production’s or such third-party operator’s future financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of Greylock Production or any such third-party operators.

In the event of any future bankruptcy of Greylock Production, the value of the Royalty Interests could be adversely affected by, among other things, delay or cessation of payments under the Royalty Interests, business disruptions or cessation of operations by the operator, replacements of operators, inability to find a replacement operator if necessary, reduced production of reserves, or decreased distributions to Trust unitholders.

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 Production 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 if a material title problem were to arise in the future, proceeds available for distribution to Trust unitholders, and the value of the Trust units, may be reduced.

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 Production now has several years of production data was about 40.9% during the first year of production, approximately 18.6% during the next three to five years of production and approximately 6.5% per year for the remainder of the economically productive life of the well.

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 Production has no contractual obligation to make capital expenditures on the Underlying Properties in the future. Furthermore, for properties on which Greylock Production is not designated as the operator, Greylock Production has no control over the timing or amount of those capital expenditures. Greylock Production 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 Production and the Trust will not receive the production resulting from such capital expenditures. If Greylock Production 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 Production 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.

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 Trust unitholders. These costs and expenses include those described below.

Substantially all of the production from the Producing Wells and the PUD Wells utilizes the GCGS. The Trust paid the initial Post-Production Services Fee to Legacy ECA for use of such system, which includes the Sponsor’s costs to gather, compress, transport, process, treat, dehydrate and market the gas. The Sponsor is permitted to increase this fee to the extent necessary to recover certain capital expenditures on the GCGS, so long as the resulting charge does not exceed the prevailing charges in the area for similar services. Additionally, the Trust is charged for the cost of fuel used in the compression process or equivalent electricity charges when electric compressors are used.

Any third-party post-production costs incurred and associated with the Trust’s interests reduces cash received by the Trust or available for distribution by the Trust to the Trust unitholders, including any amounts paid by Greylock Production for transportation on downstream interstate pipelines. Such post-production costs include the costs incurred in connection with Greylock Production’s agreement with a third party to obtain firm transportation downstream of the GCGS at the third party’s filed tariff rate, which is currently $0.4376 per MMBtu at a one hundred percent load factor since April 1, 2025, increasing by $0.0075 per MMBtu annually (through March 31, 2028). The current agreement provides for firm transportation for 39,901 MMBtu per day through December 31, 2027. The current rate under the Transportation Agreement was set in 2025 pursuant to a settlement between Columbia and certain shippers in proceedings before the Federal Energy Regulatory Commission. For more information regarding the Transportation Agreement, see “Business—Marketing and Post-Production Services” in Item 1 of this Form 10-K.

Taxes allocated to or imposed on the Trust include Pennsylvania franchise tax and any applicable property, ad valorem, production, severance, excise and other similar taxes. Currently, there are no taxes in Pennsylvania related to the production or severance of oil and natural gas in Pennsylvania; however, there have been proposals to enact a severance tax, none of which were adopted, in both the Pennsylvania Senate Finance Committee and the House Energy and Environmental Resources Committees. A bill that would create a natural gas severance tax has been introduced in the 2025-2026 legislative session, and currently it remains pending in the Pennsylvania Senate Finance Committee. Lawmakers may propose other taxes in the future. If adopted, such taxes would be a post-production cost that is borne by the Trust.

The Trust bears 100% of Trust administrative expenses, including fees paid to the Trustee and the Delaware Trustee and an annual administrative services fee of $60,000 payable to Greylock Production.

The Trust is also responsible for paying other expenses, including costs associated with annual and quarterly reports to Trust unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees and registrar and transfer agent fees.

The amount of costs and expenses borne by the Trust may vary materially from quarter-to-quarter. The extent to 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 Trust unitholders.

The Trust’s source of capital is the cash flows from the Royalty Interests. Pursuant to the Trust Agreement, the Trust may establish a cash reserve through the withholding of cash for contingent liabilities and to pay expenses, which will reduce the amount of cash otherwise available for distribution to unitholders.

Since the first quarter of 2019, the Trustee has been gradually building a cash reserve for the payment of future expenses and liabilities of the Trust by withholding cash reserve amounts from each quarterly distribution. In November 2021, the Trustee notified the Sponsor that the Trustee had determined to increase the targeted cash reserve from the initially stated amount of approximately $1.8 million, to approximately $3.8 million. From the first quarter of 2019 through the fourth quarter of 2022, the Trustee withheld an amount from each distribution equal to the greater of $90,000 or 10% of the amount distributable to unitholders. Since achieving the initial target of $1.8 million in the quarter ended December 31, 2022, the Trustee has been withholding, and currently plans to continue to withhold, $90,000 per quarter until a total of approximately $3.8 million in cash reserves is withheld. These withholdings are in addition to the existing cash reserve of $0.5 million, which is determined prior to the payments of quarterly expenses. The Trustee may increase or decrease the targeted amount at any time and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the Trust unitholders.

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 differential may vary significantly due to market conditions, the quality and location of production and other factors. Greylock Production 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 in March 2014. Consequently, the Trust 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.

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

Greylock Production is a privately held, independent energy company engaged in the exploration, development, production, gathering and aggregation and sale of natural gas and oil, in the Appalachian and Uinta Basins in the United States. Greylock Production is also the operator of all of the Producing Wells and all of the PUD Wells. The conveyances also provide that Greylock Production 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 Production to fulfill these numerous obligations, the value of the Royalty Interests and the Trust’s ultimate cash available for distribution will be highly dependent on Greylock Production’s performance. Greylock Production 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 Production.

The ability of Greylock Production to perform its obligations to the Trust will depend on Greylock Production’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 Production.

Due to uncertainty under Pennsylvania law, the Royalty Interests conveyed by Legacy ECA 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 Production, as the assignee of Legacy ECA, in the event of Greylock Production’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 Production 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 generated from the Royalty Interests may be commingled, for a period of time, with proceeds of the Sponsor’s retained interest. The Trust may not have adequate facts to trace its entitlement to funds in the commingled pool of funds, and other persons may, in asserting claims against the Sponsor’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 Production, payments of the royalties may be delayed or deferred; moreover, 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 Production, the Trust’s ability to foreclose on the Royalty Interest Lien, and the ability to collect cash payments from customers being held in Greylock Production’s accounts that are attributable to production from the Underlying Properties in which the Trust has a Royalty Interest, 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 Production was able to achieve.

Risks Related to the Structure of the Trust

The Trust units are a passive investment that entitles the Trust unitholders only to receive cash distributions attributable to the Royalty Interests. Neither the Trust nor the Trust unitholders has any voting rights with respect to Greylock Production and therefore none of them has any managerial, contractual or other ability to influence Greylock Production’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 Production, which also retains the right to transfer operations of any or all of the Underlying Properties. Any third-party operators may not have the operational expertise of Greylock Production 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, and neither the Trustee nor the Trust unitholders have any contractual right to replace an operator.

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 Production’s obligations relating to the Royalty Interests on the portion of the Underlying Properties sold, and Greylock Production would have no continuing obligation to the Trust with respect to those properties. Additionally, Greylock Production 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 Production.

The Trustee must sell the Royalty Interests if Trust 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. 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. As a result of the eventual termination of the Trust, Trust unitholders may not recover the value of their investment.

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

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

Greylock Production’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. Additionally, Greylock Production may abandon a well which is uneconomic to it while such well is still generating royalty income for the Trust unitholders. Greylock Production may make decisions with respect to expenditures and decisions to allocate resources on projects in other areas that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future. In making such decisions, Greylock Production 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.

Greylock Production may sell some or all of the Underlying Properties. Any such sale may not be in the best interests of the Trust unitholders. Any purchaser may lack Greylock Production’s experience in the Marcellus Shale or its creditworthiness.

Greylock Production may, without the consent of the Trust unitholders, require the Trust to release Royalty Interests with an aggregate value to the Trust of up to $5.0 million during any 12-month period. These releases may be made only in connection with the sale by Greylock Production of the Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such Royalty Interests. See “Sale and Abandonment of Underlying Properties” in Item 2 of this report.

Greylock Production may in its discretion increase its Post-Production Services Fee for post-production costs on the GCGS to the extent necessary to recover certain capital expenditures on the GCGS.

Greylock Production is permitted under the conveyance agreements creating the Royalty Interests to enter into new processing and transportation contracts without obtaining bids from or otherwise negotiating with any independent third parties, and Greylock Production will deduct from the Trust’s proceeds any charges under such contracts attributable to production from the Underlying Properties in which the Trust has a Royalty Interest. Provisions in the conveyance agreements, however, require that charges under future contracts with affiliates of Greylock Production relating to processing or transportation of natural gas must be comparable to charges prevailing in the area for similar services.

Greylock Production can purchase or sell Trust units without considering the effects the transaction may have on Trust unit prices or on the Trust itself. Additionally, Greylock Production can vote its Trust units in its sole discretion.

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 Production, 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 Trust unitholders to remove or replace the Trustee without the cooperation of Greylock Production (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.

Financial information of the Trust is not prepared in accordance with GAAP.

The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from GAAP financial statements.

The Trust is a smaller reporting company and benefits from certain reduced governance and disclosure requirements, including that the Trust’s independent registered public accounting firm is not required to attest to the effectiveness of the Trust’s internal control over financial reporting. The Trust cannot be certain if the omission of reduced disclosure requirements applicable to smaller reporting companies will make the Trust Units less attractive to investors.

Currently, the Trust is a “smaller reporting company,” meaning that the outstanding Trust Units held by nonaffiliates had a value of less than $250 million at the end of the Trust’s most recently completed second fiscal quarter. As a smaller reporting company, the Trust is not required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, meaning the Trust’s auditors are not required to attest to the effectiveness of the Trust’s internal control over financial reporting. As a result, investors and others may be less comfortable with the effectiveness of the Trust’s internal controls and the risk that material weaknesses or other deficiencies in internal controls go undetected may increase. In addition, as a smaller reporting company, the Trust takes advantage of its ability to provide certain other less comprehensive disclosures in its SEC filings, including, among other things, providing only two years of audited financial statements in annual reports. Consequently, it may be more challenging for investors to analyze the Trust’s results of operations and financial prospects, as the information the Trust provides to Trust unitholders may be different from what one might receive from other public companies in which one holds shares. As a smaller reporting company, the Trust is not required to provide this information.

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

The Trust Agreement permits the Trustee and the Trust to sue Greylock Production or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the Royalty Interests. If the Trustee does not take appropriate action to enforce the terms 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 Production or any other third party other than the Trustee. As a result, Trust unitholders will not be able to sue Greylock Production 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 Production 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.

Risks Related to Ownership of the Trust Units

The Trust units are traded on the OTCID Basic Market. As a result, Trust unitholders may have more difficulty selling Trust units or obtaining accurate quotations of the Trust units than if the Trust units were traded on a national securities exchange.

The Trust units are traded on the OTCID Basic Market, which is operated by OTC Markets Group Inc. (“OTCID Basic”) under the trading symbol “ECTM”. A trading market for the Trust units might not continue to exist on the OTCID Basic. Moreover, current trading levels might not be sustained or could diminish. Securities traded on the over-the-counter markets are typically less liquid than stocks that trade on the New York Stock Exchange. Trading on the OTCID Basic may negatively affect the trading price and liquidity of the Trust units and could result in larger spreads in the bid and ask prices for Trust units. Unitholders may find it difficult to resell their Trust units.

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

As of December 31, 2025, Greylock Production held no Trust units, while select Private Investors held Trust 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 Trust units by such holders. If the Private Investors were to sell or offer to sell a substantial number of Trust units, the market price of the Trust units could be adversely affected.

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.

Legal, Environmental and Regulatory Risks

Greylock Production 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 Production to significant liabilities.

Greylock Production’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 Production must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. Greylock Production 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 Production’s business, financial condition and results of operations. Greylock Production must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent Greylock Production 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 Production 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 Production 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.

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 state budget deficits and other reasons, several states periodically have evaluated 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 unitholders and, therefore, negatively impact the value of an investment in the Trust units.

New laws or regulations, or changes to existing laws or regulations, may unfavorably impact Greylock Production, could result in increased operating costs and have a material adverse effect on Greylock Production’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 EPA and the Pennsylvania Department of Environmental Protection may adopt new regulations regarding air emissions, water discharges, or waste management that could increase the cost of drilling and operating natural gas wells.

Meanwhile, 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 Production and third party downstream natural gas transporters. These and other potential regulations could increase Greylock Production’s operating costs, reduce Greylock Production’s liquidity, delay Greylock Production’s operations, increase direct and third party post production costs associated with the Trust’s interests or otherwise alter the way Greylock Production conducts its business, any of which could have a material adverse effect on Greylock Production’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 Production for transportation on downstream interstate pipelines.

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

The natural gas exploration and production operations of Greylock Production 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 Production’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 Production’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 Production’s operations in affected areas.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of Greylock Production’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 Production 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 Production 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 Production’s wells are drilled and facilities where Greylock Production’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 Production 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 Production 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 Production 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 Production produces, while the physical effects of climate change could disrupt Greylock Production’s production and cause Greylock Production to incur significant costs in preparing for or responding to those effects.

The Trump Administration’s efforts to roll back federal regulation of greenhouse gases (“GHGs”) represent a significant shift in federal climate policy, though the ultimate impact of those efforts on Greylock Production is unclear. In 2009, the EPA found that emissions of carbon dioxide, methane and other GHGs may present an endangerment to public health and the environment and subsequently issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed oil and gas sources – as well as the EPA’s methane emissions guidelines for existing oil and gas sources that were adopted in 2024. The EPA also has adopted rules requiring the reporting of GHG emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. Shortly after President Trump took office in January 2025, the federal government embarked on a series of changes relating to climate policy and regulation. On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement. In July 2025, the EPA issued a proposed rule to rescind the 2009 GHG endangerment finding that provided a basis for GHG regulation under the CAA. In September 2025, the EPA proposed to rescind the GHG reporting program for sectors other than the oil and gas sector, while proposing to suspend GHG reporting requirements for the oil and gas sector until 2034. In February 2026, the EPA adopted a final rule repealing its prior endangerment finding, which opens the door for the EPA to repeal its GHG rules for the oil and gas sector.

The EPA has established methane standards for oil and gas sources under the CAA based on the now-repealed GHG endangerment finding. In 2024, the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from new oil and gas sources and will require further emissions reductions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029. In 2025, however, the EPA extended certain compliance deadlines for both new and existing sources, and the 2026 endangerment finding repeal provides a basis for undoing the oil and gas methane standards, though the fact that the oil and gas standards address both methane and volatile organic compounds, which are regulated independently of the EPA’s authority to regulate GHGs, may limit the impact of future changes to the methane standards that currently apply to oil and gas sources.

The Inflation Reduction Act of 2022 (“IRA”) included new CAA section 136(c) directing the EPA to collect the Waste Emissions Charge (“WEC”) from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with the EPA’s new or existing source methane requirements. The EPA adopted new rules to implement the WEC program in November 2024; however, the fate of the WEC and the EPA rules implementing the WEC is unclear. In March 2025, President Trump signed legislation repealing the EPA’s 2024 WEC rules under the Congressional Review Act. The repeal of the EPA’s WEC rules did not eliminate the statutory requirement to pay the WEC, but it eliminated the rules established by the EPA to determine the WEC due, the payment mechanism, and any payment deadlines. The U.S. Congress may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.

Meanwhile, 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. For example, the states of Colorado and New Mexico have adopted rules regulating GHGs from the oil and gas industry that are based on the federal standards. In addition, Congress may consider adopting legislation to reduce emissions of greenhouse gases. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on Greylock Production’s business, capital expenditures, financial condition and results of operations.

The adoption and implementation of regulations imposing reporting obligations on, or limiting emissions of GHGs from, Greylock Production’s equipment and operations could require Greylock Production 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 Production’s products by making its products less desirable than competing sources of energy. To the extent that its products are competing with lower GHG-emitting energy, Greylock Production’s products may become less desirable in the market with more stringent limitations on greenhouse gas emissions. Greylock Production cannot predict with any certainty at this time how these possibilities may affect its operations.

In addition, future regulatory initiatives in the U.S. related to climate change disclosure or reporting could adversely affect the Trust. In 2024, the SEC issued a final rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The final rule mandates extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy and greenhouse gas emissions, for certain public companies. The SEC’s climate disclosure rule was challenged in court, and in March 2025 the SEC announced that it had voted to end its defense of the 2024 rule. The outcome of that litigation or separate rule changes made by the SEC may result in changes to climate-related disclosure requirements. Even in the absence of federal requirements, however, some states have adopted climate disclosure laws or rules that are not affected by the SEC’s review. Compliance with the federal or state disclosure rules may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on the personnel, systems and resources of Greylock Production or the Trust or both.

Cybersecurity Risks

Greylock Energy increasingly relies on information technology (“IT”) systems and networks in connection with its business activities, including certain of its exploration, development and production activities. Greylock Energy relies on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities of oil and natural gas reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties. As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication. These threats pose a risk to the security of Greylock Energy’s systems and networks, the confidentiality, availability and integrity of its data and the physical security of its employees and assets. This risk is exacerbated with the advancement of technologies like artificial intelligence, which malicious third parties are using to create new, sophisticated and more frequent attacks. Furthermore, geopolitical tensions or conflicts, such as the ongoing wars in Ukraine and in the Persian Gulf, may further heighten the risk of cybersecurity attacks.

Greylock Energy has experienced, and expects to continue to experience, attempts from hackers and other third parties to gain unauthorized access to its IT systems and networks. Although prior cyber-attacks have not had a material adverse effect on Greylock Energy’s operations or financial performance, Greylock Energy might not be successful in preventing cyber-attacks or mitigating their effect. Any cyber-attack could have a material adverse effect on Greylock Energy’s reputation, competitive position, business, financial condition and results of operations, and could have a material adverse effect on the Trust. Cyber-attacks or security breaches also could result in litigation or regulatory action, as well as significant additional expense to Greylock Production to implement further data protection measures.

In addition to the risks presented to Greylock Energy’s systems and networks, cyber-attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery to markets. A cyber-attack of this nature would be outside Greylock Energy’s ability to control but could have a material adverse effect on Greylock Energy’s business, financial condition and results of operations, and could have a material adverse effect on the Trust.

Cyber-attacks or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of the Trustee’s operations.

The Trustee depends heavily upon IT systems and networks in connection with its business activities. Despite a variety of security measures implemented by the Trustee, events such as the loss or theft of back-up tapes or other data storage media could occur, and the Trustee’s computer systems could be subject to physical and electronic break-ins, cyber-attacks and similar disruptions from unauthorized tampering, including threats that may come from external factors, such as governments, organized crime, hackers and third parties to whom certain functions are outsourced, or may originate internally from within the respective companies.

If a cyber-attack were to occur, it could potentially jeopardize the confidential, proprietary and other information processed and stored in, and transmitted through, the Trustee’s computer systems and networks, or otherwise cause interruptions or malfunctions in the operations of the Trust, which could result in litigation, increased costs and regulatory penalties. Although steps are taken to prevent and detect such attacks, it is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure to these consequences.

Tax Risks Related to the Trust 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 IRS were to treat the Trust as a corporation for United States federal income tax purposes, then its cash available for distribution 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 the Trust’s 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 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 likely would be required to pay state income tax. Distributions to Trust unitholders generally would be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to Trust unitholders. Because additional tax would be imposed upon the Trust as a corporation, its cash available for distribution to Trust unitholders would be substantially reduced. Therefore, treatment of the Trust as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Trust unitholders, likely causing a substantial reduction in the value of the Trust units.

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

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 state budget deficits and other reasons, several states periodically have evaluated 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 Trust unitholders 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 2018, 2019, 2020 and 2021 the then-sitting Governor of Pennsylvania proposed a tiered severance tax on the value of natural gas at the wellhead and the Governor continued to make statements promoting the enactment of a severance tax. While the details of those proposals were unclear, the Governor had indicated the percentage may vary between 3 percent and 5 percent depending on sales pricing. 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. To date, Pennsylvania’s current Governor has not put forth any proposal for the enactment of a severance tax. A bill that would create a natural gas severance tax has been introduced in the 2025-2026 legislative session, and currently it remains pending in the Pennsylvania Senate Finance Committee. Any such severance tax, if adopted, would be a cost that would be borne by the Trust and could materially reduce distributions to unitholders. Pennsylvania already imposes an “Impact fee” based on production, the effect of which is similar to that of a severance tax.

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 the Trust to change its 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.

Unless the Trust is eligible to (and chooses to) elect to issue revised Schedules K-1 to the Trust’s 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 Trust 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, the Trust may be required to change the allocation of items of income, gain, loss and deduction among the Trust unitholders.

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.

Each Trust unitholder is required to pay taxes on the Trust unitholder’s share of the Trust’s income even if a unitholder does not receive any cash distributions from the Trust.

Because the Trust unitholders are treated as partners to whom the Trust allocates taxable income that could be different in amount than the cash the Trust distributes, each Trust unitholder may be required to pay any United States federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of the Trust’s taxable income even if a unitholder receives no cash distributions from the Trust. A Trust unitholder may not receive cash distributions from the Trust equal to the Trust unitholder’s share of the Trust’s taxable income or even equal to the actual tax liability that result from that income.

Under current law for the taxable year ending December 31, 2026, the highest marginal United States federal income tax rate applicable to ordinary income of individuals is 37% and the highest marginal United States federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 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 (as well as certain estates and trusts). 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. For a Trust unitholder that is an individual, 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 modified adjusted gross income exceeds $250,000 (if the Trust unitholder is married and filing jointly) or $200,000 (if the Trust unitholder is unmarried).

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

If a Trust unitholder sells its Trust units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those Trust units. Because distributions in excess of a Trust unitholder’s allocable share of the Trust’s net taxable income decrease the Trust unitholder’s adjusted tax basis in its Trust units, the amount, if any, of such prior excess distributions with respect to the Trust units unitholders sell will, in effect, become taxable income to unitholders if unitholders sell such Trust units at a price greater than the unitholder’s tax basis in those Trust units, even if the price the unitholder receives is less than the unitholder’s 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 organizations and non-United States persons face unique tax issues from owning the Trust units that may result in adverse tax consequences to them.

Tax-Exempt Organizations. Employee benefit plans and most other organizations exempt from United States federal income tax including individual retirement accounts (known as IRAs) and other retirement plans are subject to United States federal income tax on unrelated business taxable income. Because all of the income of the Trust is expected to be royalty income, interest income and gain from the sale of real property, none of which is expected to be unrelated business taxable income, any such organization exempt from United States federal income tax is not expected to be taxed on income generated by ownership of Trust units so long as neither the property held by the Trust nor the Trust units are debt-financed property within the meaning of IRC Section 514(b). However, such investors should consult their own tax advisors as to the proposed treatment of income from the Trust.

Non-U.S. Persons. Pursuant to IRC Section 1446, withholding tax on income effectively connected to a United States trade or business allocated to non-U.S. persons (“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 non-U.S. persons should be made at a 30% rate unless the rate is reduced by treaty. Nominees and brokers should withhold at the highest marginal rate on distributions made to non-U.S. persons. A non-U.S. holder’s gain on the sale of Trust units is treated 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. A transferee of units is also required to withhold 10% of the amount realized on the sale or exchange of units (generally, the purchase price) unless the transferor certifies that it is not a nonresident alien individual or foreign corporation or another exception is available.

The Trust treats 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 may adopt positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely alter the tax effects of an investment in Trust units. It also could affect the timing of tax benefits or the amount of gain from a Trust unitholder’s sale of Trust units and could have a negative impact on the value of the Trust units or result in audit adjustments to a Trust unitholder’s tax returns.

Because a Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of the loaned Trust units, the Trust unitholder may no longer be treated for United States federal income tax purposes as a partner with respect to those Trust units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of the Trust’s income, gain, loss or deduction with respect to those Trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Trust units could be fully taxable as ordinary income. The Trust’s counsel has not rendered an opinion regarding the treatment of a Trust 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 may 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 basis 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.

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 United States federal income tax laws could negatively affect the Trust’s financial condition and results of operations.

Item 1B. Unresolved Staff Comments.

None.

Item 1C. Cybersecurity.

The Trust has no directors or executive officers. The affairs of the Trust are managed by the Trustee. The Trust falls under the cybersecurity program of The Bank of New York Mellon Corporation (“BNY Mellon”), the parent corporation of The Bank of New York Mellon Trust Company, N.A. As further described in its 2025 Annual Report, BNY Mellon maintains a broad range of defenses aimed at remaining abreast of and responding to evolving cybersecurity threats impacting it, its operations, its clients, its third-party service providers and the broader financial services sector.

Risk Management Strategy and Procedures

BNY Mellon has implemented policies and procedures designed to detect, prevent and respond to malicious and accidental disruptions to the delivery of critical technology services. BNY Mellon’s cybersecurity risk management program is embedded in its three lines of defense model.

As part of its first line of defense, BNY Mellon maintains a dedicated Cybersecurity organization, led by the Chief Information Security Officer (the “CISO”), that is responsible for the day-to-day management of risks from cybersecurity threats. Cybersecurity’s responsibilities include cybersecurity threat intelligence, incident response and other cybersecurity operations aimed at enabling BNY Mellon to identify, assess and manage existing and emerging cybersecurity threats. Cybersecurity monitors for potential threats and communicates relevant risks to the CISO and other members of executive management. Additionally, Cybersecurity maintains a cybersecurity incident response and reporting process pursuant to which cybersecurity incidents are classified according to their severity based upon an assessment of multiple factors. Certain cybersecurity incidents may activate enterprise-wide resiliency processes, which include, among other things, escalation through the management and Board committee structures described below. In addition, BNY Mellon maintains a preparedness program designed to reinforce cybersecurity risk management practices and compliance with BNY Mellon’s policies and procedures. The preparedness program includes mandatory training for all employees, contractors and consultants, enhanced training for those in roles presenting higher risk, calibrated phishing email simulations, distribution of information security awareness materials and cybersecurity event simulation exercises. In addition, BNY Mellon leverages both internal and external assessments and engages with third-party assessors, consultants and auditors to evaluate and test its cybersecurity controls and provide guidance on potential improvements, including design and operating effectiveness. BNY Mellon’s information security management system is certified to the ISO 27001 standard by an independent, accredited certification body, and BNY Mellon maintains this certification through periodic external audits and ongoing monitoring.

BNY Mellon has a defined third-party governance framework to help manage the risk posed to it by the use of third-party service providers. BNY Mellon evaluates the risk posed by third-party service engagements based on multiple factors. BNY Mellon has protocols that seek to mitigate cybersecurity risks associated with third-party service providers based on the risk level assigned to such third party, which may include mandatory contractual obligations or the implementation of additional controls by BNY Mellon and/or the applicable service provider.

Cybersecurity is subject to ongoing review and challenge from Technology Risk Management, which is a part of the independent second line of defense risk function. Technology Risk Management, together with the broader Risk & Compliance group, is responsible for and manages BNY Mellon’s risk management framework and establishes guidance for Cybersecurity and management designed to help identify, assess and manage cybersecurity risk.

BNY Mellon’s Internal Audit function serves as the third line of defense and provides an independent view on how effectively the organization as a whole manages cybersecurity risk.

Risk Management Oversight and Governance

BNY Mellon’s management is responsible for assessing and managing BNY Mellon’s material risks from cybersecurity threats with oversight provided by its Board of Directors (the “Board”) and the Board committees. The Risk Committee of the Board has primary responsibility for oversight of the overall operation of BNY Mellon’s risk management framework, including policies and practices addressing cybersecurity risk, and is responsible for the oversight of the second line of defense with respect to its cybersecurity risk management responsibilities. The Technology Committee of the Board and the full Board regularly receive reports and briefings from management concerning cybersecurity matters, including any significant changes to BNY Mellon’s cybersecurity program. BNY Mellon also has protocols for escalating cybersecurity threats and incidents to the Technology Committee of the Board and the full Board. In addition, the Audit Committee of the Board monitors and oversees the performance of Internal Audit, including with respect to its cybersecurity risk management responsibilities.

At the management level, BNY Mellon’s Technology Oversight Committee, which is the senior management committee responsible for the governance and oversight of BNY Mellon’s significant technology projects and initiatives, reviews reports from management concerning Cybersecurity and is responsible for, among other things, escalating issues, including significant cybersecurity threats and incidents, to the Technology Committee of the Board and the full Board of Directors. The Technology Oversight Committee is chaired by the Chief Information Officer and Global Head of Engineering (the “CIO”).

BNY Mellon’s Technology Risk Committee is the most senior governance committee primarily focused on cybersecurity and technology risk issues and is a part of the second line of defense risk function. It is responsible for, among other things, overseeing and reviewing emerging cybersecurity risks, significant cybersecurity incidents and remediation plans. The Technology Risk Committee receives reports from management and has protocols for escalating certain issues and risks to the Enterprise Risk Committee and the Risk Committee of the Board. The Technology Risk Committee is chaired by the Chief Technology Risk Officer. Members include key leaders from the first line of defense, including the CISO.

BNY Mellon’s CIO, CISO and Chief Technology Risk Officer each have extensive experience in assessing and managing risks from cybersecurity threats. BNY Mellon’s CIO joined BNY Mellon in 2024 from a large multinational company, where she was responsible for overseeing information technology and cybersecurity operations. BNY Mellon’s CISO joined BNY Mellon in 2025 and previously led the global assurance function for cybersecurity and technology controls at a global systemically important financial institution. BNY Mellon’s Chief Technology Risk Officer joined BNY Mellon in 2024 and has previous experience as Global Head of Cyber, Technology and Information Security Risk Management at a global systemically important financial institution and over a decade of experience serving the U.S. intelligence community in a variety of cybersecurity-related positions. BNY Mellon believes that refreshing leadership in the CIO, CISO and Chief Technology Risk Officer roles brings new perspectives and specialized expertise to enhance cybersecurity practices, while continuity is safeguarded through disciplined succession and transition planning.

Item 2. Properties.

The Underlying Properties

The Underlying Properties consist of the working interests owned by Greylock Production 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, 2025, the total natural gas reserves attributable to the Royalty Interests were 14.9 Bcf. Greylock Production operates all of the wells subject to the Royalty Interests although it is not contractually obligated to the Trust to continue as the operator. 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 Royalty 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, 2025. 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, 2025, 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, 2025 through December 31, 2025, and were held constant for the life of the properties. This yielded an average realized price for natural gas of $2.87 per Mcf. The net revenues attributable to the Trust’s reserves are net of the Trust’s obligation to reimburse Greylock Production 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 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 December 19, 2025 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		14,944	$	32,583	$	17,576

(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 the estimated reserve quantities attributable to the Royalty Interests. 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 Production’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 Production’s senior management reviewed and approved all Ryder Scott reserve reports contained herein.

Greylock Production’s reserves are reviewed by the Reservoir Engineering Manager. The Reservoir Engineering Manager has a Bachelor of Science degree in Petroleum Engineering. He has over fourteen years of oil and gas industry experience with nine years directly related in Reservoir Engineering. During that time, he has focused on reserves estimates and economics.

Sale and Abandonment of Underlying Properties

Greylock Production 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 Production and the Trust in determining whether a well is capable of producing in commercially paying quantities, Greylock Production 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 Production 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 Production 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 Production 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 Production 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.

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 Production’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 Production as part of the Acquisition.

Greylock Production’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:

royalties and other burdens, express and implied, under gas leases;

production payments and similar interests and other burdens created by Greylock Production or its predecessors in title;

a variety of contractual obligations arising under operating agreements, Farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;

liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;

pooling, unitization and communitization agreements, declarations and orders;

easements, restrictions, rights-of-way and other matters that commonly affect property;

conventional rights of reassignment that obligate Greylock Production to reassign all or part of a property to a third party if Greylock Production intends to release or abandon such property; and

rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and the Royalty Interests therein.

Greylock Production believes that the burdens and obligations affecting the Underlying Properties and the Royalty Interests are conventional in the industry for similar properties. Greylock Production 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 Production 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, Legacy ECA obtained a preliminary title review to ensure there were no obvious defects in title to the well. Legacy ECA 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, Legacy ECA recorded the conveyances of the Royalty Interests in the real property records of Pennsylvania in accordance with local recording acts. Legacy ECA also has granted to the Trust the Royalty Interest Lien to provide protection to the Trust, in the event of a bankruptcy of Greylock Production (as successor to Legacy ECA), 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 Production in the Producing Wells. Greylock Production 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 Production’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 Production’s interest in any of the wells subject to the PUD Royalty Interest was subject to burdens in excess of 12.5%, such burdens will be fully allocated against the Sponsor’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 Production’s net revenue interest in the well. Greylock Production 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 Production owns a 100% working interest in a PUD Well, the applicable net revenue interest is calculated by multiplying Greylock Production’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 Production’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 Production 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 the amount calculated based on estimated production volumes attributable to the Producing Wells after deducting the Trust’s proportionate share of:

any taxes or fees levied on the severance or production of the natural gas produced from the Producing Wells and any property taxes attributable to the natural gas production attributable to the Producing Wells; and

post-production costs, which generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Charges payable to the Sponsor for such post-production costs on the GCGS were limited to $0.52 per MMBtu of natural gas gathered until Legacy ECA fulfilled its drilling obligation in 2011; since then, the Sponsor has been permitted to increase the Post-Production Service Fee to the extent necessary to recover certain capital expenditures in the GCGS. Additionally, the Trust is charged for the cost of fuel used in the compression process, including equivalent electricity charges in instances when electric compressors are used.

Proceeds payable to the Trust from the sale of natural gas production attributable to the Producing Wells in any calendar quarter 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.

The Trust has no future well locations nor drilling opportunities under the AMI or otherwise.

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 Production 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 the amount calculated based on estimated production volumes attributable to the PUD Wells after deducting the Trust’s proportionate share of:

any taxes or fees levied on the severance or production of the natural gas produced from the PUD Wells and any property taxes attributable to the gas produced from the PUD Wells; and

post-production costs, which generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Charges payable to the Sponsor for such post-production charges on the GCGS were limited to $0.52 per MMBtu of gas gathered until Legacy ECA fulfilled its drilling obligation in 2011; since then, the Sponsor has been permitted to increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the GCGS. Additionally, the Trust is charged for the cost of fuel used in the compression process, including equivalent electricity charges in instances when electric compressors are used.

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

are determined on the basis that Greylock Production’s working interest with respect to the PUD Wells is not subject to burdens (landowner’s royalties and other similar interests) in excess of 12.5% of the proceeds from natural gas production attributable to Greylock Production’s interest; and

are 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 underlying PUD properties, including any costs to plug and abandon a well included in the underlying PUD properties.

Royalty Interest Lien

Under the laws of Pennsylvania, it is not clear that the Royalty Interests conveyed by Legacy ECA to the Trust would be treated as real property interests. Therefore, at the time of the conveyance Legacy ECA granted to the Trust a lien (the “Royalty Interest Lien”) to provide protection to the Trust, exercisable in the event of a bankruptcy of Legacy ECA (including its successor, Greylock Production), 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 the Sponsor’s retained interest in the PUD and Producing Wells and the AMI or other interest of Greylock Production in the AMI, and Greylock Production has the right to lien, mortgage, sell or otherwise encumber the Sponsor’s retained interest subject to the Royalty Interest Lien.

Legacy ECA recorded the conveyances of the Royalty Interests and a Mortgage/Fixture Filing in the real estate records of Greene County, Pennsylvania and 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 Production’s interest with respect to the PDP properties is greater than what was warranted to the Trust in the conveyances, Greylock Production 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 Production’s interest been the amount warranted.

Additional Provisions

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

amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the underlying property until actually collected;

amounts received by the owner of the underlying property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and

amounts received by the owner of the underlying property and not deposited with an escrow agent will be considered to have been received.

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

The conveyances generally permit Greylock Production 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 Production’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 Production 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 Production 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 Production 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 Production 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 Production must maintain books and records sufficient to determine the amounts payable for the Royalty Interests to the Trust. Quarterly and annually, Greylock Production 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.

PART II

The Trust units have traded on the OTCID Basic Market (“OTCID Basic”), operated by OTC Markets Group Inc., since July 1, 2025, having previously traded on the OTC Pink Market (“OTC Pink”) from July 31, 2020 through June 30, 2025, in each case under the symbol “ECTM”. Prior to July 31, 2020, the Trust units were listed and traded on the New York Stock Exchange under the symbol “ECT”.

The following table shows the high and low sales/bid prices, as applicable, per Trust unit as reported on the OTC Pink for 2024 and the first two quarters of 2025, and as reported on the OTCID Basic for the final two quarters of 2025. Quotations on the OTC Pink and the OTCID Basic reflect bid and ask quotations, may reflect inter-dealer prices, without retail markup, markdown or commission, and may not represent actual transactions.

	High		Low
Calendar Quarter 2025
First Quarter	$	0.55	$	0.43
Second Quarter	$	0.68	$	0.46
Third Quarter	$	0.65	$	0.53
Fourth Quarter	$	0.63	$	0.48

Calendar Quarter 2024
First Quarter	$	0.52	$	0.34
Second Quarter	$	0.54	$	0.40
Third Quarter	$	0.52	$	0.40
Fourth Quarter	$	0.49	$	0.37

At March 24, 2026, the 17,605,000 units outstanding were held by 24 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).

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 2025.

Item 6. [Reserved]

Item 7. Trustee’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. All information regarding operations has been provided by Greylock Energy.

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 Energy”), including Greylock Production, LLC (“Greylock Production”), which serves as operator of the subject wells, and Greylock Midstream, LLC (“Greylock Midstream”), whose subsidiaries market and gather certain of the gas, 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”).

As part of the initial acquisition of substantially all of Legacy ECA’s assets, neither Greylock Energy nor Greylock Production acquired title ownership of Legacy ECA’s working interest in two wells in which the Trust also had an interest, the Penneco Morrow #1MH and Penneco Morrow #2MH wells. In March 2019, Legacy ECA sold the title ownership and working interest in these two wells to Greylock Production.

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, 2025 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 the Sponsor’s interest in the Producing Wells for a period of 20 years commencing on April 1, 2010 and 45% thereafter. The PUD Royalty Interest entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to the Sponsor’s interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter.

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 GCGS were limited to $0.52 per MMBtu gathered until Legacy ECA fulfilled its drilling obligation in 2011; since then, the Sponsor has been permitted to increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the GCGS.

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 Production’s net revenue interest in the well. Greylock Production 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 Production owns a 100% working interest in a PUD Well, the applicable net revenue interest is calculated by multiplying Greylock Production’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 Production’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 begin to liquidate in March 2030 and will soon thereafter wind up its affairs and terminate.

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

natural gas prices received;

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

post-production costs and any applicable taxes; and

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

The markets for natural gas are volatile. The outbreak of war between Russia and Ukraine in February 2022 and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which has further enhanced the volatility in natural gas prices since early 2022. The extent and duration of the war in Ukraine, sanctions and resulting market disruptions could be significant, including significant volatility in commodity prices, supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increases in cyberattacks and espionage, each of which could have a substantial impact on the global economy and consequently the Trust’s business for an unknown period of time. In addition, the war against Iran and the related geopolitical instability in the Middle East also could have a disruptive effect on global natural gas markets. Although the events in Ukraine and the Middle East are not currently expected to have a material impact on the Trust’s business, cash flows, liquidity or financial condition, neither Greylock Energy nor the Trustee can predict the progress or outcome of the wars in Ukraine or in the Persian Gulf, as these conflicts, and any resulting government reactions, are evolving and beyond the control of Greylock Energy or the Trust. Meanwhile, economic conditions, such as inflation or higher unemployment rates, or changes in economic policies, such as further increases in tariffs or trade barriers, could affect the demand for natural gas. As a result of these and other factors, prices for natural gas, and therefore the Trust’s quarterly cash distributions, might not be maintained for any significant period.

Pursuant to IRC Section 1446, withholding tax on income effectively connected to a United States trade or business allocated to non-U.S. persons (“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 non-U.S. persons should be made at a 30% rate unless the rate is reduced by treaty. Nominees and brokers should withhold at the highest marginal rate on distributions made to non-U.S. persons. A non-U.S. holder’s gain on the sale of Trust units is treated 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. A transferee of units is also required 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 or other exception is available. Pursuant to final Treasury Regulations issued in 2020, this withholding obligation applies to transfers of units in publicly traded partnerships such as the Trust (which is classified as a partnership for United States federal and state income tax purposes).

Results of Trust Operations

For the twelve months ended December 31, 2025 compared to the twelve months ended December 31, 2024

Distributable income for the year ended December 31, 2025 increased to $2.2 million from $0.8 million for the year ended December 31, 2024. Compared to the year ended December 31, 2024, royalty income increased $1.6 million while general and administrative expenses decreased $0.1 million.

Royalty income increased from $2.2 million for the year ended December 31, 2024 to $3.8 million for the year ended December 31, 2025, an increase of $1.6 million. This was due to an increase in the average realized price, partially offset by a decrease in production.

The average price realized for the year ended December 31, 2025 increased $1.07 per Mcf to $2.18 per Mcf as compared to $1.11 for the year ended December 31, 2024. The increase in the average sales price for gas production was due primarily to an increase in the weighted average monthly closing NYMEX price partially offset by a decrease to the average Basis. The average sales price, before post-production costs, increased from $1.73 per Mcf for the year ended December 31, 2024 to $2.87 per Mcf for the year ended December 31, 2025. This increase in price was primarily the result of an increase in the weighted average monthly closing NYMEX price for the current period to $3.43 per MMBtu compared to the year ended December 31, 2024 weighted average monthly closing NYMEX price of $2.27 per MMBtu, partially offset by a $0.06 per MMBtu decrease in the average Basis to $(0.65) per MMBtu in the current period compared to the prior period Basis of $(0.59) 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. Overall, average post-production costs increased to $0.69 per Mcf for the year ended December 31, 2025 as compared to $0.63 per Mcf for the year ended December 31, 2024 primarily due to an increase in firm transportation.

Production decreased 12.2% from 1,964 MMcf for the year ended December 31, 2024 to 1,724 MMcf for the year ended December 31, 2025.

General and administrative expenses paid by the Trust decreased $0.1 million to $1.18 million for the year ended December 31, 2025 compared to $1.24 million for the year ended December 31, 2024. For the years ended December 31, 2025 and 2024, the Trustee withheld approximately $0.4 million and $0.2 million, respectively, towards the cash reserve that the Trustee has established for the payment of future liabilities of the Trust as they become due. The addition to the cash reserve decreased distributable income in each of the years ended December 31, 2025 and 2024.

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 Production 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 Production 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.

Since the first quarter of 2019, the Trustee has been gradually building a cash reserve for the payment of future expenses and liabilities of the Trust by withholding cash reserve amounts from each quarterly distribution. In November 2021, the Trustee notified the Sponsor that the Trustee had determined to increase the targeted cash reserve from the initially stated amount of approximately $1.8 million, to approximately $3.8 million. From the first quarter of 2019 through the fourth quarter of 2022, the Trustee withheld an amount from each distribution equal to the greater of $90,000 or 10% of the amount distributable to unitholders. Since achieving the initial target of $1.8 million in the quarter ended December 31, 2022, the Trustee has been withholding, and currently plans to continue to withhold, $90,000 per quarter until a total of approximately $3.8 million in cash reserves is withheld. As of December 31, 2025, the Trustee has withheld from the funds otherwise available for distribution a total amount of approximately $2.7 million plus $0.3 million interest toward the building of the $3.8 million cash reserve. These withholdings are in addition to the existing cash reserve of $0.5 million, which is determined prior to the payments of quarterly expenses. The Trustee may increase or decrease the targeted amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the unitholders.

Payments to the Trust in respect of the Royalty Interests are based on the 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.

Pursuant to the terms of the ASA, the Trust is obligated to pay Greylock Production an annual administrative services fee of $60,000 for accounting, bookkeeping and informational services relating to the Royalty Interests to be performed by Greylock Production 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, 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. This fee was $175,607 and $180,876 in 2024 and 2025, respectively. The Trust is also obligated to pay the Delaware Trustee a fee of $2,500 per year, throughout the term of the Trust.

Greylock Production and the Trustee each may terminate the provisions of the ASA relating to Greylock Production’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 Production may not terminate the ASA except in connection with Greylock Production’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.

Critical Accounting Policies and Estimates

The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles in the United States of America (“GAAP”). Accordingly, the financial statements of the Trust differ from financial statements prepared in accordance with GAAP. For example, amortization of the Trust’s investment in the royalty interests is calculated on a unit-of-production basis and is charged directly to Trust Corpus. This other comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission (“SEC”), as specified by Staff Accounting Bulletin Topic 12:E, 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 of distributable income shows distributable income, defined as income of the Trust available for distribution to the Trust unitholders before application of those unitholders’ additional expenses, if any, for depreciation, depletion, and amortization, interest and income taxes. The royalty income is reflected net of existing royalties and overriding royalties and have been reduced by gathering/post-production expenses.

Royalty income 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 royalty income, which is 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 is assessed to determine whether the net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to 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 may involve 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 forward pricing curves. No impairment indicators were identified during either of the years ended December 31, 2025 or 2024, and accordingly no impairments were present. Significant dispositions or abandonment of the Underlying Properties, if necessary, are charged to Royalty Interests and the Trust Corpus.

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

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

As a “smaller reporting company” as defined in Item 10 of Regulation S-K, the Trust is not required to provide information required by this Item.

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, 2025 and 2024, and the related statements of distributable income and trust corpus for the years then ended, 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, 2025 and 2024, and the results of its distributable income and changes in trust corpus for the years then ended, 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 Trust 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.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to those charged with governance and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosure to which it relates.

	*Valuation of Royalty Interest in Gas Properties*

Description of the Matter	At December 31, 2025, the Trust’s net royalty interest in gas properties was $9.1 million. As discussed in Note 3 to the financial statements, the royalty interest in gas properties is assessed to determine whether the net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. The Trust determines whether an impairment charge is necessary to its investment in the royalty interest in gas properties if total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. Auditing the Trust’s royalty interest in gas properties impairment assessment required additional audit effort because, in determining whether an impairment occurred, the Trust considers estimates of the future cash flows attributable to the underlying properties, which can be influenced by assumptions about future market and economic conditions, such as changes in realized prices.

How We Addressed the Matter in Our Audit	To test the Trust’s impairment assessment, our audit procedures included, among others, assessing the methodology and testing the assumptions and the underlying data used by the Trust in its analysis. We compared the pricing assumption used by management to current industry and economic trends as well as external forward pricing sources. Furthermore, we searched for and evaluated information that corroborates or contradicts the Trust’s assumptions utilized in the impairment assessment by performing procedures including, but not limited to assessment of the historical accuracy of management’s estimates and assessing the sensitivity of assumptions by evaluating the changes in the value of the royalty interest in gas properties that would result from changes in those assumptions.

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

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

March 24, 2026

ECA Marcellus Trust I

Statements of Assets, Liabilities, and Trust Corpus

As of December 31,

	2025			2024
ASSETS:
Cash and cash equivalents	$	3,234,214		$	2,693,762
Royalty income receivable		945,495			743,882
Royalty interest in gas properties		352,100,000			352,100,000
Accumulated amortization		(342,957,873	)		(341,817,662	)
Net royalty interest in gas properties		9,142,127			10,282,338
Total Assets	$	13,321,836		$	13,719,982
LIABILITIES AND TRUST CORPUS:
Liabilities:
Distributions payable to unitholders	$	642,425		$	347,101
Trust corpus; 17,605,000 common units authorized, issued and outstanding		12,679,411			13,372,881
Total Liabilities and Trust Corpus	$	13,321,836		$	13,719,982

See notes to the audited financial statements.

ECA Marcellus Trust I

Statements of Distributable Income

	Year Ended December 31, 2025			Year Ended December 31, 2024
Royalty income	$	3,764,277		$	2,175,257
Net proceeds to Trust	$	3,764,277		$	2,175,257
General and administrative expense		(1,179,350	)		(1,237,468	)
Interest income		128,899			139,176
Income available for distribution prior to cash reserves		2,713,826			1,076,965
Cash reserves withheld by Trustee		(360,000	)		(167,769	)
Interest withheld on cash reserves		(109,072	)		(114,793	)
Distributable income available to unitholders	$	2,244,754		$	794,403
Distributable income per common unit (17,605,000 units authorized and outstanding for 2025 and 2024)	$	0.128		$	0.045

See notes to the audited financial statements.

ECA Marcellus Trust I

Statements of Trust Corpus

	Year Ended December 31, 2025			Year Ended December 31, 2024
Trust Corpus, Beginning of Period	$	13,372,881		$	14,236,383
Cash reserves withheld, including interest		469,072			282,562
Distributable income		2,244,754			794,403
Distributions paid or payable to unitholders		(2,267,085	)		(808,630	)
Amortization of royalty interest in gas properties		(1,140,211	)		(1,131,836	)
Impairment of royalty interest in gas properties		—			—
Trust Corpus, End of Period	$	12,679,411		$	13,372,881

See notes to the audited financial statements.

ECA MARCELLUS TRUST I

NOTES TO AUDITED FINANCIAL STATEMENTS

NOTE 1. Organization of the Trust

ECA Marcellus Trust I (the “Trust”) is a Delaware statutory trust formed in March 2010 by Energy Corporation of America 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 (as defined below), 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 Trust is authorized to issue a total of 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 the Sponsor’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 the Sponsor’s interest in the PUD Wells. In November 2017, Greylock Energy, LLC and certain of its wholly owned subsidiaries, including Greylock Production, LLC (“Greylock Production”), which serves as operator of the subject wells, and Greylock Midstream, LLC (“Greylock Midstream”), whose subsidiaries market and gather certain of the gas, acquired substantially all of the assets of Legacy ECA, as described in Note 4.

References to “Greylock Energy” are to Greylock Energy, LLC and certain of its wholly owned subsidiaries, including Greylock Production and Greylock Midstream. References to “Legacy ECA” are to Energy Corporation of America and its wholly owned subsidiaries, and, when discussing the conveyance documents, the Private Investors as described in the prospectus dated July 1, 2010 and filed with the Securities and Exchange Commission pursuant to Rule 424(b) under the Securities Act of 1933, as amended, on July 1, 2010 relating to the initial public offering of the Trust units, as such entities existed prior to the Acquisition (as defined in Note 4). References to the “Sponsor” are to Legacy ECA, for periods prior to the Acquisition (as defined in Note 4), and to Greylock Energy, for periods after the Acquisition.

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 Perpetual 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 the Sponsor for such post-production costs on the GCGS were limited to $0.52 per MMBtu gathered until Legacy ECA fulfilled its drilling obligation in November 2011; since then, the Sponsor has been permitted to increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the GCGS. 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.

Unless sooner terminated as provided in the Amended and Restated Trust Agreement among the Trust, Legacy ECA and the Trustee (as amended, the “Trust Agreement”), the Trust will begin to liquidate on or about March 31, 2030 (the “Termination Date”). The Term Royalty Interests will revert automatically to Greylock Production at the Termination Date, and the Perpetual Royalty Interests will be sold pursuant to a marketing process expected to commence soon thereafter, with the net proceeds, if any, from the sale to be distributed pro rata to the Trust unitholders. Greylock Production has a right of first refusal to purchase the Perpetual Royalty Interests being sold by the Trust following the termination of the Trust.

The Trust Agreement provides that the Trust will terminate if gross proceeds to the Trust attributable to the Royalty Interests over any four consecutive quarters are less than $1.5 million. If this early termination event occurs, the Trust Agreement will require the Trustee to sell the Royalty Interests, either by private sale or public auction, subject to Greylock Energy's right of first refusal to purchase the Royalty Interests. After the sale of all of the Royalty Interests, payment of all Trust liabilities and establishment of reasonable provisions for the payment of additional anticipated or contingent Trust expenses or liabilities, the Trustee will distribute the net proceeds of the sale to the Trust unitholders. Gross proceeds received by the Trust attributable to the Royalty Interests over the four consecutive quarters ended December 31, 2025 were approximately $3.8 million. The gross proceeds attributable to the Royalty Interests are dependent upon, among other factors, the volume of hydrocarbons extracted and sold from the Underlying Properties and the price realized on those sales. The Trust has no control or influence over the volumes sold or the proceeds realized from those sales. Accordingly, while the gross proceeds received by the Trust attributable to the Royalty Interests over the four consecutive quarters ended December 31, 2025 exceeded $1.5 million, future gross proceeds could fall below that threshold.

The Trust has no directors, officers or employees. The business and affairs of the Trust are administered by The Bank of New York Mellon Trust Company, N.A., as Trustee. The duties of the Trustee are defined by the Trust Agreement. The Trustee does not make operating or business decisions affecting the assets of the Trust, and the Trustee’s functions under the Trust Agreement are ministerial in nature. Although Greylock Production operates all of the Producing Wells and all of the PUD Wells, Greylock Production has no ability to manage or influence the management of the Trust. Additionally, 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 royalty income and expenses during the reporting period. Without limiting the foregoing statement, the information furnished is based upon certain estimates of the royalty income 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 on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States (“GAAP”). This other comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission (“SEC”), as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Amortization of the Trust’s investment in the royalty interests is calculated on a unit-of-production basis and is charged directly to Trust Corpus. 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 of distributable income 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 royalty income is presented net of existing royalties and overriding royalties and have been reduced by gathering/post-production expenses.

Cash:

Cash equivalents may include highly liquid instruments maturing in three months or less from the date acquired.

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 royalty income and expenses during the reporting period. Actual results could differ from those estimates.

Royalty Income and Expenses:

The Trust uses the accrual basis to recognize royalty income, which is recorded as reserves are extracted from the Underlying Properties and sold. Expenses are recognized when paid.

Royalty Interest in Gas Properties:

The Royalty interest in gas properties is assessed to determine whether the net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to 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 interest in gas properties if total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. Determination as to whether and how much an asset is impaired may involve estimates of fair value, which is determined based on discounted cash flow techniques using assumptions including projected revenues, future commodity prices, production costs, and a market-specific average cost of capital. Estimates of undiscounted future net revenues attributable to proved gas reserves utilize forward pricing curves. No impairment indicators were identified during either of the years ended December 31, 2025 or 2024, and accordingly no impairments were present. Significant dispositions or abandonment of the Underlying Properties, if necessary, are charged to Royalty Interests and the Trust Corpus.

NOTE 4. Reaffirmation Agreement

On November 29, 2017, Greylock Energy 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 the Royalty Interest (the “Acquisition”).

In connection with the Acquisition, Greylock Production assumed all of Legacy ECA’s obligations under the Trust Agreement and other instruments to which Legacy ECA and the Trustee were 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 Production, 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 Production (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 United States federal and state income tax purposes. 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, 2025 or 2024.

NOTE 6. Related Party Transactions

Trustee Administrative Fee:

Under the terms of the Trust Agreement, the Trustee charges an annual administrative fee, subject to adjustment each year, that was $150,000 from inception through 2017. The annual fee was $175,607 and $180,876 in 2024 and 2025, respectively. The Trust deducts these costs, as well as those to be paid to Greylock Production pursuant to the Administrative Services Agreement referred to below, in the period paid.

Administrative Services Fee:

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

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, 2024 to December 31, 2025:

	Natural Gas (MMcf)
Balance at January 1, 2024		19,803
Revisions of previous estimates		(2,291	)
Production		(1,964	)
Balance at December 31, 2024		15,548
Revisions of previous estimates		1,120
Production		(1,724	)
Balance at December 31, 2025		14,944

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 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):

	2025			2024
Future cash inflows	$	42,894		$	26,834
Future production costs		(10,311	)		(9,795	)
Future net cash flows before discount		32,583			17,039
10% discount to present value		(15,007	)		(7,350	)
Standardized measure of discounted future net cash flows(1)	$	17,576		$	9,689

(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, 2024 to December 31, 2025 in the standardized measure of discounted future net cash flows relating to proved reserves (in thousands):

Standardized measure, January 1, 2024	$	14,004
Net proceeds to the Trust		(2,175	)
Revisions of previous estimates		(1,428	)
Accretion of discount		1,400
Net change in price and production cost		(1,531	)
Other		(581	)
Standardized measure, December 31, 2024	$	9,689
Net proceeds to the Trust		(3,764	)
Revisions of previous estimates		1,317
Accretion of discount		969
Net change in price and production cost		7,644
Other		1,721
Standardized measure, December 31, 2025	$	17,576

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 Production 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 Production, 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 “Trustee’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 Production 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 in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework). Based on the Trustee’s evaluation under the framework in Internal Control—Integrated Framework, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2025.

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 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, 2025, 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 Production.

Item 9B. Other Information.

Rule 10b5-1 Trading Plans. During the three months ended December 31, 2025, no officer or employee of the Trustee who performs policy-making functions for the Trust adopted, modified, or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement, as such terms are defined in Item 408(a) of Regulation S-K, with respect to the Trust units.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Not applicable.

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.

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.

Insider Trading Policy

Because the Trust has no directors, officers or employees, and because the Trustee does not have the authority under the terms of the Trust Agreement to engage in transactions in the Trust units on behalf of the Trust, the Trust has not adopted an insider trading policy applicable to such persons or to the Trust itself. It is the policy of the Trustee that any transaction in Trust units by any officer or employee of the Trustee who performs policy-making functions for the Trust must comply with the insider trading policies of The Bank of New York Mellon Corporation., the parent corporation of The Bank of New York Mellon Trust Company, N.A.

Item 11. Executive Compensation.

During the years ended December 31, 2024 and 2025, the Trustee received administrative fees of $175,607 and $180,876, respectively, 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.

(a)

Securities Authorized for Issuance Under Equity Compensation Plans.

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

(b)

Security Ownership of Certain Beneficial Owners.

Based solely on filings with the SEC, the Trustee is not aware of any holders of 5% or more of the Trust units as of March 24, 2026.

(c)

Security Ownership of Management.

Not applicable.

(d)

Changes in Control.

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.

Administrative Services Agreement

Under the terms of the Administrative Services Agreement, the Trust pays a quarterly administration fee of $15,000 to Greylock Production. General and administrative expenses in the Trust’s statements of distributable income for the years ended December 31, 2025 and 2024 include $60,000 in administrative fees for each year. Greylock Production and the Trustee each may terminate the provisions of the Administrative Services Agreement relating to the provision by Greylock Production 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 Production may not terminate the Administrative Services Agreement except in connection with Greylock Production’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, through 2017 the Trust paid an annual administrative fee to the Trustee of $150,000, paid in four quarterly installments of $37,500. Beginning in 2018 and subject to the allowable adjustment to the annual administrative fee, the Trustee has increased the annual fee each year. The annual fee was $175,607 and $180,876 in 2024 and 2025, respectively. 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, 2025 and 2024 included administrative fees of approximately $180,876 and $175,607, respectively. Variances in the amount of the annual fee may also be 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 Accountant Fees and Services.

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, 2026. During fiscal 2025 and 2024, 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, 2025 and 2024 by Ernst & Young LLP:

	2025		2024
Audit fees(1)	$	193,500	$	186,000
Audit-related fees		—		—
Tax fees		205,000		205,000
All other fees		—		—
Total fees	$	398,500	$	391,000

(1)

Fees for audit services included fees for the reviews of the Trust’s quarterly financial statements.

The Trust has no audit committee, and as a result, has no audit committee pre-approval policies and procedures with respect to fees paid to Ernst & Young LLP. Any pre-approval or approval of any services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.

PART IV

Item 15. Exhibit and Financial Statement Schedules

(a)(1) Financial Statements

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

Report of Independent Registered Public Accounting Firm (PCAOB Identification No. 42)	53
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2025 and 2024	55
Statements of Distributable Income for the Years Ended December 31, 2025 and 2024	56
Statements of Trust Corpus for the Years Ended December 31, 2025 and 2024	57
Notes to Financial Statements	58
Supplemental Reserve Information (Unaudited)	61

(a)(2) Schedules

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

(a)(3) Exhibits

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

Exhibit Number		Description
3.1		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)).
4.1		Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (Incorporated herein by reference to Exhibit 4.1 to the Trust’s Annual Report on Form 10-K filed on March 23, 2020 (File No. 001-34800)).
10.1		Perpetual Overriding Royalty Interest Conveyance (PDP), dated effective April 1, 2010, from Energy Corporation of America to The Bank of New York Mellon Trust Company, N.A., as Trustee (Incorporated herein by reference to Exhibit 10.1 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)).
10.2		Perpetual Overriding Royalty Conveyance (PUD), dated effective April 1, 2010, from Energy Corporation of America to The Bank of New York Mellon Trust Company, N.A., as Trustee (Incorporated herein by reference to Exhibit 10.2 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)).
10.3		Private Investor Conveyance, dated July 7, 2010, among ECA Marcellus Trust I and certain private investors named therein (Incorporated herein by reference to Exhibit 10.3 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)).
10.4		Assignment of Royalty Interest, dated effective April 1, 2010, from Eastern Marketing Corporation to The Bank of New York Mellon Trust Company, N.A., as Trustee (Incorporated herein by reference to Exhibit 10.4 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)).
10.5		Term Overriding Royalty Interest Conveyance (PDP), dated effective April 1, 2010 from Energy Corporation of America to Eastern Marketing Corporation (Incorporated herein by reference to Exhibit 10.5 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)).
10.6		Term Overriding Royalty Conveyance (PUD), dated effective April 1, 2010, from Energy Corporation of America to Eastern Marketing Corporation (Incorporated herein by reference to Exhibit 10.6 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)).
10.7		Administrative Services Agreement, dated July 7, 2010, between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee (Incorporated herein by reference to Exhibit 10.7 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)).
10.8		Royalty Interest Lien, dated July 7, 2010, by and between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee (Incorporated herein by reference to Exhibit 10.11 to the Trust’s Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)).
10.9		Registration Rights Agreement, dated July 7, 2010, by and among ECA Marcellus Trust I, Energy Corporation of America, and certain affiliates of Energy Corporation of America (Incorporated herein by reference to Exhibit 10.12 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 LLP.
23.2*		Consent of Ryder Scott Company, L.P.
31*		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1		Report of Ryder Scott Company, L.P. dated December 18, 2024 (included in Appendix A to this report).

Filed herewith.

Item 16. Form 10-K Summary

None.

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 I

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

	By:	/s/ Sarah Newell Sarah Newell Vice President

March 24, 2026

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.

Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

The Trust does not send an annual report to security holders or proxy material with respect to any annual or other meeting of security holders to its security holders.

Appendix A-1


TBPELS REGISTERED ENGINEERING FIRM F-1580
555 17TH STREET SUITE 985	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

December 19, 2025

ECA Marcellus Trust I

The Bank of New York Mellon Trust Company, N.A.

601 Travis Street, 16^th Floor

Houston, Texas 77002

Ladies and 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, 2025. The subject properties are located 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 December 19, 2025, 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, 2025.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2025, 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 considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; 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.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

ECA Marcellus Trust I

December 19, 2025

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Royalty Interests of

ECA Marcellus Trust I

As of December 31, 2025

	Total
	Proved Developed
	Producing
Net Reserves
Gas – MMcf		14,944

Income Data ($M)
Future Gross Revenue	$	42,894
Deductions		10,311
Future Net Income (FNI)	$	32,583

Discounted FNI @ 10%	$	17,576

Values may not sum to total due to rounding.

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 the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. 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. The Trust owns only a royalty interest, and the operating costs utilized in our evaluation serve only the purpose of calculating economic limits. However, certain electricity, gathering and firm transportation costs paid by the Trust are included and shown as “Other” deductions in the cash flows. The future net income is before the deduction 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

ECA Marcellus Trust I

December 19, 2025

Page 3

	Discounted Future Net Income ($M)
	As of December 31, 2025
Discount Rate	Total
Percent	Proved
9	$	18,356
12	$	16,234
15	$	14,629
18	$	13,367

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 reserves status categories are defined in 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 reserves 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 these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal categories, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized 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 reserves 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.

The operations in which the Trust owns a royalty interest 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, drilling and 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

ECA Marcellus Trust I

December 19, 2025

Page 4

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 reserves evaluator in the process of estimating the quantities of reserves. Reserves 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.

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 reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves 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 to be achieved than not.” 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 reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves 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 decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data available through November 2025. The data utilized in this analysis were furnished to Ryder Scott by the Trust and were considered sufficient for the purpose thereof.

To estimate economically producible 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 which 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.

The Trust 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 the Trust 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, 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 the Trust. 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

ECA Marcellus Trust I

December 19, 2025

Page 5

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.

We furnished the Trust with the above-mentioned average benchmark price in effect on December 31, 2025. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark price appropriate to the geographic area where the hydrocarbons are sold. This benchmark price is 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 the Trust. The differentials furnished by the Trust were reviewed by us for their reasonableness using information furnished by the Trust for this purpose.

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

Price

North America

United States

Gas

Henry Hub

$3.387/MMBTU

$2.87/Mcf

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

ECA Marcellus Trust I

December 19, 2025

Page 6

Costs

Operating costs for the leases and wells in this report were furnished by the Trust. They are based on the operating expense reports of the operator and include only those costs directly applicable to the leases or wells. The Trust only owns a royalty interest in the subject wells and the operating expenses supplied by the Trust were used only to determine the economic life of each property. However, per specific contractual terms, certain electricity, gathering and firm transportation costs paid by the Trust are included and shown as “Other” deductions in the cash flows. The costs furnished to us were reviewed by us for their reasonableness using information furnished by the Trust for this purpose. 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

ECA Marcellus Trust I

December 19, 2025

Page 7

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 approximately 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 receive 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. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to the Trust. 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 analyses 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.

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, 2025 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 papers 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.
	TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

ECA Marcellus Trust I

December 19, 2025

Page 8

	/s/ Stephen E. Gardner
	Stephen E. Gardner, P.E.	[SEAL]
	Colorado License No. 44720
	Managing Senior Vice President

SEG (DRO)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide, as well as for coordinating and supervising the evaluations of staff and consulting engineers of the company. Mr. Gardner is also a member of Ryder Scott’s Board of Directors. 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 https://ryderscott.com/employees/denver-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 a member of the Society of Petroleum Engineers (SPE) and a former director of the Society of Petroleum Evaluation Engineers (SPEE). He currently serves as an officer for SPEE at the international level.

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 2024 continuing education hours, Mr. Gardner attended multiple technical conferences, including the SPEE Annual Meeting and the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, geothermal energy, reserves definitions and guidelines, SEC comment letter trends, ethics, and others. Mr. Gardner attended the 2024 Geothermal Rising Conference, where he presented a technical paper on geothermal resource classifications. In addition, Mr. Gardner participated in various local technical seminars and other internal company training courses throughout the year covering topics such as reserves evaluation methods and evaluation software, ethics, M&A trends, regulatory issues, enhanced geothermal systems, and more.

Based on his educational background, professional training and approximately 20 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 June 2019.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

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 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. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

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. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. 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, 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

(ii) 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.

(iii) 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.

(iv) 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:

(A) 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

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1)

completion intervals that are open at the time of the estimate but which have not yet started producing;

(2)

wells which were shut-in for market conditions or pipeline connections; or

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

ECA Marcellus Trust I 10-K