Item 1. Financial Statements.
ECA Marcellus Trust I
Statements
of Assets, Liabilities, and Trust Corpus
| | |
June 30, | | |
December 31, | |
| |
2022 | | |
2021 | |
| ASSETS: | |
| | |
| |
| Cash | |
$ | 1,773,484 | | |
$ | 1,703,483 | |
| Royalty income receivable | |
| 3,458,976 | | |
| 2,636,468 | |
| Royalty interest in gas properties | |
| 352,100,000 | | |
| 352,100,000 | |
| Accumulated amortization | |
| (338,830,195 | ) | |
| (338,156,565 | ) |
| Net royalty interest in gas properties | |
| 13,269,806 | | |
| 13,943,435 | |
| | |
| | | |
| | |
| Total Assets | |
$ | 18,502,266 | | |
$ | 18,283,386 | |
| | |
| | | |
| | |
| LIABILITIES AND TRUST CORPUS: | |
| | | |
| | |
| Liabilities: | |
| | | |
| | |
| Distributions payable to unitholders | |
$ | 3,106,817 | | |
$ | 2,390,496 | |
| Trust corpus; 17,605,000 common units authorized, issued and
outstanding | |
| 15,395,449 | | |
| 15,892,890 | |
| | |
| | | |
| | |
| Total Liabilities and Trust Corpus | |
$ | 18,502,266 | | |
$ | 18,283,386 | |
See
notes to the unaudited financial statements.
ECA Marcellus Trust I
Statements
of Distributable Income
| | |
Six Months Ended | | |
Three Months Ended | |
| | |
June 30 | | |
June 30 | |
| | |
2022 | | |
2021 | | |
2022 | | |
2021 | |
| Royalty income | |
$ | 5,559,807 | | |
$ | 2,053,381 | | |
$ | 3,458,976 | | |
$ | 1,018,242 | |
| Net proceeds to Trust | |
$ | 5,559,807 | | |
$ | 2,053,381 | | |
$ | 3,458,976 | | |
$ | 1,018,242 | |
| | |
| | | |
| | | |
| | | |
| | |
| General and administrative expense | |
| (620,024 | ) | |
| (836,665 | ) | |
| (262,981 | ) | |
| (438,657 | ) |
| Interest income | |
| 1,876 | | |
| 68 | | |
| 1,817 | | |
| 37 | |
| | |
| | | |
| | | |
| | | |
| | |
| Income available for distribution prior to cash reserves | |
$ | 4,941,659 | | |
$ | 1,216,784 | | |
$ | 3,197,812 | | |
$ | 579,622 | |
| | |
| | | |
| | | |
| | | |
| | |
| Cash reserves withheld by Trustee | |
| (180,000 | ) | |
| (180,000 | ) | |
| (90,000 | ) | |
| (90,000 | ) |
| Interest withheld on cash reserves | |
| (1,028 | ) | |
| (47 | ) | |
| (995 | ) | |
| (26 | ) |
| | |
| | | |
| | | |
| | | |
| - | |
| Distributable income available to unitholders | |
$ | 4,760,631 | | |
$ | 1,036,737 | | |
$ | 3,106,817 | | |
$ | 489,597 | |
| |
| | | |
| | | |
| | | |
| | |
| Distributable income per common unit | |
| | | |
| | | |
| | | |
| | |
| (17,605,000 units authorized and outstanding) | |
$ | 0.270 | | |
$ | 0.059 | | |
$ | 0.176 | | |
$ | 0.028 | |
See
notes to the unaudited financial statements.
ECA Marcellus Trust I
Statements
of Trust Corpus
| | |
Three Months Ended | |
| | |
June 30, | |
| | |
2022 | | |
2021 | |
| Trust Corpus, Balance at April 1, | |
$ | 15,639,928 | | |
$ | 16,808,167 | |
| Cash reserves withheld, including interest | |
| 90,995 | | |
| 90,026 | |
| Distributable income | |
| 3,106,817 | | |
| 489,597 | |
| Distributions paid or payable to unitholders | |
| (3,107,873 | ) | |
| (488,211 | ) |
| Amortization of royalty interest in gas properties | |
| (334,418 | ) | |
| (426,610 | ) |
| Impairment of royalty interest in gas properties | |
| - | | |
| - | |
| Trust Corpus, Balance at June 30, | |
$ | 15,395,449 | | |
$ | 16,472,968 | |
| | |
Six Months Ended | |
| | |
June 30, | |
| | |
2022 | | |
2021 | |
| Trust Corpus, Balance at January 1, | |
$ | 15,892,890 | | |
$ | 17,133,939 | |
| Cash reserves withheld, including interest | |
| 181,028 | | |
| 180,047 | |
| Distributable income | |
| 4,760,631 | | |
| 1,036,737 | |
| Distributions paid or payable to unitholders | |
| (4,765,471 | ) | |
| (1,043,926 | ) |
| Amortization of royalty interest in gas properties | |
| (673,630 | ) | |
| (833,830 | ) |
| Impairment of royalty interest in gas properties | |
| - | | |
| - | |
| Trust Corpus, Balance at June 30, | |
$ | 15,395,449 | | |
$ | 16,472,968 | |
See
notes to the unaudited financial statements.
ECA MARCELLUS TRUST I
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
NOTE 1. Organization of the Trust
ECA Marcellus Trust I is a Delaware statutory trust
formed in March 2010 by Energy Corporation of America (“Legacy ECA”) to own royalty interests in 14 producing horizontal natural
gas wells producing from the Marcellus Shale formation, all of which are online and are located in Greene County, Pennsylvania (the “Producing
Wells”), and royalty interests in 52 horizontal natural gas development wells subsequently drilled to the Marcellus Shale formation
(the “PUD Wells”) within the “Area of Mutual Interest”, or “AMI”, comprising approximately 9,300 acres
held by Legacy ECA, of which it owned substantially all of the working interests, in Greene County, Pennsylvania. The effective date of
the Trust was April 1, 2010; consequently, the Trust received the proceeds of production attributable to the PDP Royalty Interest (defined
herein) from that date even though the PDP Royalty Interest was not conveyed to the Trust until the closing of the initial public offering
on July 7, 2010. The total number of units the Trust is authorized to issue is 17,605,000 units, all of which are now common units. The
royalty interests were conveyed from Legacy ECA’s working interest in the Producing Wells and the PUD Wells limited to the Marcellus
Shale formation (the “Underlying Properties”). 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 of the assets of Legacy ECA, as described in Note 4.
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
initial 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 initial interest in the PUD Wells.
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 Greene County Gathering System
(“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. Additionally, if electric compression is utilized in lieu of gas as fuel in the compression process, the Trust will be charged
for the electric usage as provided for in the Trust conveyance documents.
The trust 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.
The Trust makes quarterly cash distributions of
substantially all of its cash receipts, after deducting Trust administrative expenses, including the costs incurred as a result of being
a publicly traded entity, on or about the 60th day following the completion of each quarter. Unless sooner terminated, the
Trust will begin to liquidate on or about March 31, 2030 (the “Termination Date”) and will soon thereafter wind up its affairs
and terminate. At the termination of the Trust, 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will revert automatically
to Greylock Production. The remaining 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will be sold, and the net proceeds
will be distributed pro rata to the unitholders soon after the termination of the Trust. Greylock Production will have a right of first
refusal to purchase the remaining 50% of the Royalty Interests at the termination of the Trust.
The business and affairs of the Trust are administered
by The Bank of New York Mellon Trust Company, N.A., as Trustee. Although 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. Neither the Trust nor the Trustee
has any authority or responsibility for, or any involvement with or influence over, any aspect of the operations on or relating to the
properties to which the Royalty Interests relate.
NOTE 2. Basis of Presentation
The preparation of financial statements requires
the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period.
Without limiting the foregoing statement, the information furnished is based upon certain estimates of the revenues attributable to the
Trust from natural gas production for the three and six months ended June 30, 2022 and 2021 and is therefore subject to adjustment in
future periods to reflect actual production for the periods presented.
The information furnished reflects all normal and
recurring adjustments which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim period
presented. The accompanying unaudited interim financial statements should be read in conjunction with the audited financial statements
and notes thereto included in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2021. The December
31, 2021 condensed balance sheet data was derived from audited financial statements, but does not include all applicable financial statement
disclosures.
NOTE 3. Significant Accounting Policies
The accompanying unaudited financial information
has been prepared by the Trustee in accordance with the instructions to Form 10-Q. The financial statements of the Trust differ from financial
statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) because
certain cash reserves may be established for contingencies, which would not be accrued in financial statements prepared in accordance
with GAAP. Amortization of the investment in overriding royalty interests calculated on a unit-of-production basis is charged directly
to Trust Corpus. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by
the U.S. Securities and Exchange Commission (“SEC”) as specified by Accounting Standard Codification (“ASC”) Topic
932, Extractive Activities—Oil and Gas: Financial Statements of Royalty Trusts. Income determined on the basis of GAAP would include
all expenses incurred for the period presented. However, the Trust serves as a pass-through entity, with expenses for depreciation, depletion,
and amortization, interest and income taxes being based on the status and elections of the Trust unitholders. General and administrative
expenses, production taxes or any other allowable costs are charged to the Trust only when cash has been paid for those expenses. In addition,
the Royalty Interests are not burdened by field and lease operating expenses. Thus, the statement shows distributable income, defined
as income of the Trust available for distribution to the Trust unitholders before application of those additional expenses, if any, for
depreciation, depletion, and amortization, interest and income taxes. The revenues are presented net of existing royalties and overriding
royalties and have been reduced by gathering/post-production expenses.
Cash:
Cash may include highly liquid instruments maturing
in three months or less from the date acquired.
Use of Estimates in the Preparation
of Financial Statements:
The preparation of financial statements requires
the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from those estimates.
Revenue and Expenses:
The Trust serves as a pass-through entity, with
items of depletion, interest income and expense, and income tax attributes being based upon the status and election of the unitholders.
Thus, the Statements of Distributable Income show Income available for distribution before application of those unitholders’ additional
expenses, if any, for depletion, interest income and expense, and income taxes.
The Trust uses the accrual basis to recognize revenue,
with royalty income recorded as reserves are extracted from the Underlying Properties and sold. Expenses are recognized when paid.
Royalty Interest in Gas Properties:
The Royalty interest in gas properties is assessed
to determine whether the net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount
may not be recoverable, pursuant to ASC Topic 360, Property, Plant and Equipment. The Trust determines whether an impairment charge is
necessary to its investment in the Royalty interest in gas properties if total capitalized costs, less accumulated amortization, exceed
undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. Determination as to whether and how
much an asset is impaired involves estimates of fair value, which is determined based on discounted cash flow techniques using assumptions
including projected revenues, future commodity prices, production costs, and market-specific average cost of capital. Estimates of undiscounted
future net revenues attributable to proved gas reserves utilize estimates of future pricing, which are generally developed based on NYMEX
forward pricing curves. If required, the Trust will recognize an impairment charge to the extent that the net capitalized costs exceed
the discounted fair value of the investment in net profits interests attributable to proved gas reserves of the Underlying Properties.
Any such impairment charge would not reduce Distributable Income, although it would reduce Trust Corpus. No impairment in the Underlying
Properties was recognized during 2021 or during the three and six months ended June 30, 2022. Significant dispositions or abandonment
of the Underlying Properties are charged to Royalty Interests and the Trust Corpus.
Amortization of the Royalty interest in gas properties
is calculated on a units-of-production basis, whereby the Trust’s cost basis in the properties is divided by Trust total proved
reserves to derive an amortization rate per reserve unit. Such amortization does not reduce Distributable Income, rather it is charged
directly to Trust Corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant
revisions are known.
The conveyance of the Royalty Interest to the Trust
was accounted for as a purchase transaction. The $352,100,000 reflected in the Statements of Assets, Liabilities and Trust Corpus as Royalty
interests in gas properties represents 17,605,000 Trust units valued at $20.00 per unit. The carrying value of the Trust’s investment
in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.
NOTE 4. Reaffirmation Agreement
On November 29, 2017, Greylock Energy acquired
substantially all of the gas production and midstream assets of Legacy ECA, including Legacy ECA’s interests in certain natural
gas properties that are subject to royalty interests held by the Trust.
In connection with the transaction, Greylock Production
assumed all of Legacy ECA’s obligations under the Amended and Restated Trust Agreement among the Trust, Legacy ECA and the Trustee
(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. As of June 30, 2022, no amounts have
been loaned to the Trust pursuant to the Letter Agreement.
NOTE 5. Income Taxes
The Trust is a Delaware statutory trust, which is
taxed as a partnership for federal and state income taxes. Accordingly, no provision for federal or state income taxes has been made.
Uncertain tax positions are accounted for under ASC Topic 740, Income Taxes (“ASC 740”), which prescribes a recognition
threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return.
Additionally, ASC 740 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure,
and transition. The Trust has not identified any uncertain tax positions through the period ended June 30, 2022.
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. The annual fee was $161,884 in 2021 and is $166,741 in 2022. 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.
| Item 2. |
Trustee's Discussion and Analysis of Financial Condition and Results of Operations. |
References to the “Trust” in this document
refer to ECA Marcellus Trust I. As discussed in “Overview” below, Greylock Energy acquired substantially all of the assets
of Energy Corporation of America in November 2017. References to “Legacy ECA” in this document refer to Energy Corporation
of America and its wholly-owned subsidiaries and, when discussing the conveyance documents, the Private Investors, as such entities existed
prior to the asset acquisition by Greylock Energy. The following review of the Trust’s financial condition and results of operations
should be read in conjunction with the financial statements and notes thereto and the audited financial statements and notes thereto included
in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2021 (the “2021 Form 10-K”). The Trust’s
annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available
on the SEC’s website at www.sec.gov and at http://ect.q4web.com/home/default.aspx. Certain terms used herein are defined in Appendix
A. All information regarding operations has been provided to the Trustee by Greylock Energy.
Note Regarding Forward-Looking Statements
This report 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 document, the words “believes,”
“expects,” “anticipates,” “intends” or similar expressions, are intended to identify such forward-looking
statements. Further, all statements regarding future circumstances or events are forward-looking statements. The following important factors,
in addition to those discussed elsewhere in this document, could affect the future results of the energy industry in general, and Greylock
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 effect, impact, potential duration, or other implications of the Coronavirus Disease 2019 (“COVID-19”) pandemic; |
| · | the outbreak of armed conflict between Russia and Ukraine and the potential destabilizing effect such conflict may pose for the European
continent or the global natural gas markets; |
| · | competition in the energy industry; |
| · | the uncertainty of estimates of natural gas reserves and production; and |
| · | other risks described under the caption “Risk Factors” in Part I, Item 1A of the 2021 Form 10-K. |
This report describes other important factors that
could cause actual results to differ materially from expectations of Greylock Energy and the Trust. 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.
Overview
The Trust is a statutory
trust created under the Delaware Statutory Trust Act. The Bank of New York Mellon Trust Company, N.A. serves as Trustee. The Trust
does not conduct any operations or activities. The Trust’s purpose is, in general, to hold the Royalty Interests (described below),
to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalty Interests after payment of Trust expenses,
and to perform certain administrative functions in respect of the Royalty Interests and the Trust units. The Trustee has no authority
or responsibility for, and no involvement with, any aspect of the oil and gas operations on the properties to which the Royalty Interests
relate. The Trust derives all or substantially all of its income and cash flows from the Royalty Interests. The Trust is treated as a
partnership for federal and state income tax purposes.
In November 2017, Greylock
Energy and certain of its wholly owned subsidiaries, including Greylock Production, LLC, which serves as operator of the subject wells,
and Greylock Midstream, LLC, 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.
In connection with the
transaction, 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.
The
Royalty Interests were conveyed to the Trust from the working interest now held by Greylock Production 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 initial 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 initial interest in the PUD Wells for a period of 20 years commencing on April 1, 2010
and 25% thereafter.
Legacy ECA was obligated
to drill all of the PUD Wells by March 31, 2014. As of November 30, 2011, Legacy ECA had fulfilled its drilling obligation to
the Trust by drilling 40 PUD Wells (52.06 Equivalent PUD Wells), calculated as provided in the Development Agreement. Consequently, no
additional wells will be drilled for the Trust. The Trust was not responsible for any costs related to the drilling of development wells
or any other development or operating costs. As of June 30, 2022, the Trust owns royalty interests in 14 Producing Wells and the 40 development
wells (52.06 Equivalent PUD Wells) that are now completed and in production.
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 and any
amounts reserved for administrative expenses. Post-production costs generally consist of costs incurred to gather, compress, transport,
process, treat, dehydrate and market the
natural gas produced. Charges (the
“Post-Production Services Fee”) 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.
Greylock Production has an agreement with Columbia
Gas Transmission, LLC (“Columbia”) to provide firm transportation downstream of the GCGS for 50,000 MMBtu per day (the
“Transportation Agreement”). The Transportation Agreement has been in effect since August 1, 2011 and provides for firm
transportation at Columbia’s filed tariff rate, which is currently $0.3154 per MMBtu at one hundred percent load factor. As amended
by Greylock Production and Columbia in September 2020, the Transportation Agreement terminated on July 31, 2022 with respect to 5,000
MMBtu per day and will terminate on December 31, 2024 with respect to the remaining 45,000 MMBtu per day.
Greylock Production and Columbia have entered into
an additional agreement, as amended in September 2020, to provide firm transportation downstream of the GCGS for 52,550 MMBtu per day
that will utilize Columbia’s Mountaineer XPress Project (the “MXP Agreement”). This firm transportation arrangement
went into effect on January 18, 2019, and is at a fixed demand rate of $0.50 per MMBtu at one hundred percent load factor plus applicable
Columbia tariff surcharges. Unless otherwise modified or altered, the MXP Agreement, as amended, will terminate on December 31, 2022.
The previously existing negotiated reservation rate will remain in place for the remaining term of the agreement. 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 will not be charged for the costs associated with modifying the firm transportation agreements with Columbia, including
the difference between the base negotiated rate and the increased negotiated rate in September 2020 and December 2021 under the MXP Agreement.
On July 31, 2020 Columbia submitted an application
to the Federal Energy Regulatory Commission (“FERC”) to increase certain tariff rates effective February 1, 2021. The FERC
issued an Order Accepting and Suspending Filing, Subject to Refund on August 31, 2021. As proposed, this tariff filing would increase
the tariff rate from $0.23/MMbtu to $0.41/MMbtu on the applicable contracts. The tariff filing was protested at the FERC, and on October
29, 2021 Columbia submitted the Stipulation and Agreement of Settlement and Motion for Shortened Comment Period in Docket No. RP20-1060-005
(the “Settlement”). The Settlement, which FERC approved on February 25, 2022, resolves all remaining issues set for hearing
by the FERC in the consolidated proceedings and adjusts the tariff rate to $0.3154/MMbtu effective December 1, 2021, requiring Columbia
to issue a refund on the difference between the initial increased rate and the final rate. Greylock Production received the refund from
Columbia in April 2022 and distributed a refund of $102,075 to the Trust during the three months ended June 30, 2022.
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 the 60th day 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 revenues 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, as demonstrated
by significant price swings experienced during 2020 and 2021 attributable primarily to the economic effects of the COVID-19 pandemic,
followed by the gradual return of demand for natural gas as economies reopened. COVID-19 and the responses by federal, state and local
governmental authorities to the pandemic have also resulted in significant business and operational disruptions, including business closures,
supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces. The full impact
of the COVID-19 pandemic is unknown and continues to evolve. The extent to which the COVID-19 pandemic negatively impacts Greylock Production
will depend on the severity, location and duration of the effects and spread of COVID-19, the actions undertaken by federal, state and
local governments and health officials to contain the virus or treat its effects, and how quickly and to what extent economic conditions
improve and normal business and operating conditions resume. A prolonged period of low natural gas prices will adversely affect Greylock
Energy. Meanwhile, the outbreak of armed conflict between Russia and Ukraine in February 2022 and the subsequent sanctions imposed
on the Russian Federation may have a destabilizing effect on the European continent and the global natural gas markets. The recent rise
in the rate of inflation, leading to increases in interest rates and a potentially recessionary economic environment in the United States,
also could have a negative effect on the demand for natural gas. As a result, prices for natural gas, and therefore the Trust’s
quarterly cash distributions, might not be maintained for any significant period of time. Low natural gas prices will reduce revenues
to the Trust, which will reduce the amount of cash available for distribution to unitholders and in certain periods could result in no
distributions to unitholders. For example, there were no distributions to unitholders for the quarters ended March 31, 2020, June 30,
2020, or September 30, 2020 as Trust expenses exceeded net revenues to the Trust.
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.
The Tax Cuts and Jobs Act (the “TCJA”) enacted in December 2017 treats a non-U.S. holder’s gain on the sale of Trust
units as ECI to the extent such holder would have had ECI if the Trust had sold all of its assets at fair market value on the date of
the sale of such Trust units. The TCJA also requires a transferee of units to withhold 10% of the amount realized on the sale of exchange
of units (generally, the purchase price) unless the transferor certifies that it is not a nonresident alien individual or foreign corporation
or another exception is available. Pursuant to final Treasury Regulations issued on October 7, 2020, this new withholding obligation applies
to transfers of units in publicly traded partnerships such as the Trust (which is classified as a partnership for federal and state income
tax purposes) occurring on or after January 1, 2022.
Results of Trust Operations
For the Three Months Ended June 30, 2022 compared to the Three Months
Ended June 30, 2021
Distributable income for the three months ended
June 30, 2022 increased to $3.1 million from $0.5 million for the three months ended June 30, 2021. Compared to the quarter ended June
30, 2021, royalty income increased by $2.4 million while general and administrative expenses decreased by $0.2 million.
Royalty income increased to $3.5 million for the
three months ended June 30, 2022 from $1.0 million for the three months ended June 30, 2021, an increase of $2.5 million. This increase
was due to an increase in the average sales price between periods offset slightly by a decrease in production.
The average price realized for the three months
ended June 30, 2022 increased $4.34 per Mcf to $5.83 per Mcf as compared to $1.49 per Mcf for the three months ended June 30, 2021. The
increase in the average sales price realized for natural gas production was due primarily to a higher average sales price and a decrease
in other post-production costs during the period. The average sales price, before post-production costs, increased from $2.44 per Mcf
for the three months ended June 30, 2021 to $6.62 per Mcf for the three months ended June 30, 2022. The increase in price was the result
of an increase in the weighted average monthly closing NYMEX price for the current period to $7.12 per MMBtu compared to the weighted
average monthly closing NYMEX price of $2.83 per MMBtu for the three months ended June 30, 2021. The average Basis per MMBtu realized
for the three months ended June 30, 2022 decreased $0.25 per Mcf to minus $0.71 per Mcf as compared to minus $0.46 per Mcf for the three
months ended June 30, 2021.
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 slightly to $0.96 per Mcf in the current period
compared to $0.95 per Mcf for the three-month period ended June 30, 2021. This slight increase was offset by the $0.1 million
refund related to the Columbia FERC tariff settlement.
Production decreased 13.2% from 683 MMcf for the
three months ended June 30, 2021 to 593 MMcf for the three months ended June 30, 2022 due to normal production declines.
General and administrative
expenses paid by the Trust decreased to $0.3 million for the three-month period ended June 30, 2022 compared to $0.4 million for the three-month
period ended June 30, 2021. This decrease was primarily due to a decrease in professional services expenses due to timing of payments.
Cash reserves of $0.1 million were withheld for each of the three-month periods ended June 30, 2022 and June 30, 2021.
For the Six Months Ended June 30, 2022 compared to the Six Months
Ended June 30, 2021
Distributable income for the six months ended June
30, 2022 increased to $4.8 from $1.0 million for the six months ended June 30, 2021. Compared to the six months ended June 30, 2021, royalty
income increased by $3.5 million and general and administrative expenses decreased by $0.2 million.
Royalty income increased to $5.6 million for the
six months ended June 30, 2022 from $2.1 million for the six months ended June 30, 2021, an increase of $3.5 million. This increase was
due to an increase in the average sales price between periods partially offset by slightly lower production between periods.
The average price realized for the six months ended
June 30, 2022 increased $3.12 per Mcf to $4.65 per Mcf as compared to $1.54 per Mcf for the six months ended June 30, 2021. The increase
in the average sales price realized for natural gas production was due primarily to a higher average sales price and lower post-production
costs associated with firm transportation during the period. The average sales price, before post-production costs, increased from $2.43
per Mcf for the six months ended June 30, 2021 to $5.50 per Mcf for the six months ended June 30, 2022. The increase in price was the
result of an increase in the weighted average monthly closing NYMEX price for the current period to $6.01 per MMBtu compared to the
weighted average monthly closing NYMEX price of $2.75 per MMBtu for the six months ended June 30, 2021. This increase was partially offset
by a slight decrease in the average Basis per MMBtu in the current period at minus $0.68 per MMBtu compared to the prior period Basis
of minus $0.39 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 $0.93 per Mcf in the current period compared
to $0.90 per Mcf for the six-month period ended June 30, 2021. This slight increase was primarily due to an increase in electric
charges but was offset by the $0.1 million refund related to the Columbia FERC tariff settlement.
Production decreased 10.6% from 1,336 MMcf for the
six months ended June 30, 2021 to 1,195 MMcf for the six months ended June 30, 2022. The decreased production was the result of natural
production declines that occur during the life of a well.
General and administrative
expenses paid by the Trust decreased to $0.6 million for the six-month period ended June 30, 2022 compared to $0.8 million for the three-month
period ended June 30, 2021. This decrease was primarily due to a decrease in professional services expenses due to timing of payments.
Cash reserves of $0.2 million were withheld for each of the six-month periods ended June 30, 2022 and June 30, 2021.
Liquidity and Capital Resources
The Trust has no source of liquidity or capital
resources other than net cash flows from the Royalty Interests. Other than Trust administrative expenses, including, if applicable, expense
reimbursements to 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 Administrative Services Agreement. Each quarter, the Trustee determines
the amount of funds available for distribution. Available funds are the excess cash, if any, received by the Trust from the Royalty Interests
and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust’s expenses for that
quarter. Available funds are reduced by any cash the Trustee determines to hold as a reserve against future expenses or liabilities. The
Trustee, on behalf of the Trust, may borrow funds required to pay expenses or liabilities if the Trustee determines that the cash on hand
and the cash to be received are insufficient to cover the Trust’s expenses or liabilities. If the Trustee borrows funds, the Trust
unitholders will not receive distributions until the borrowed funds are repaid.
Commencing
with the distribution paid to unitholders in the first quarter of 2019, the Trustee has been gradually building a cash reserve for the
payment of future expenses and liabilities of approximately $1.8 million by withholding cash reserve amounts from each quarterly
distribution equal to the greater of $90,000 or 10% of the amount distributable to unitholders. In November 2021, the Trustee notified
the Sponsor that the Trustee has determined to increase its targeted cash reserve for the payment of future expenses and liabilities to
approximately $3.8 million. In February 2022, the Trustee withheld $90,000 from funds otherwise available for distribution and plans to
continue to withhold the greater of $90,000 or 10% until the cash reserve exceeds its initial target of $1.8 million. Thereafter the Trustee
will withhold $66,175 per quarter until a total of approximately $3.8 million in cash reserves is withheld. 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. Cash held in
reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for
the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to unitholders, together
with interest earned on the funds. For the quarter ended June 30, 2022, the Trustee withheld $90,000 from the funds otherwise available
for distribution and withheld a minimal amount of interest earned on the cash reserve balance. As of June 30, 2022, the Trustee has withheld
from the funds otherwise available for distribution a total amount of approximately $1.5 million plus a minimal amount of interest toward
the building of the $3.8 million cash reserve.
Payments to the Trust in respect of the Royalty
Interests are based on the complex provisions of the various conveyances held by the Trust, copies of which are filed as exhibits to the
2021 Form 10-K, and reference is hereby made to the text of the conveyances for the actual calculations of amounts due to the Trust.
The Trust does not have any transactions, arrangements
or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability
of capital resources.
Significant Accounting Policies
The
financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles
in the United States of America (“GAAP”) because, among other differences, certain cash reserves may be established for contingencies,
which would not be accrued in financial statements prepared in accordance with GAAP. Amortization of the investment in overriding royalty
interests calculated on a unit-of-production basis is charged directly to Trust Corpus. This comprehensive basis of accounting other than
GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by ASC Topic 932 Extractive Activities—Oil
and Gas: Financial Statements of Royalty Trusts.
Income determined on the basis of GAAP would include
all expenses incurred for the period presented. However, the Trust serves as a pass-through entity, with expenses for depreciation, depletion,
and amortization, interest and income taxes being based on the status and elections of the Trust unitholders. General and administrative
expenses, production taxes or any other allowable costs are charged to the Trust only when cash has been paid for those expenses. In addition,
the Royalty Interests are not burdened by field and lease operating expenses. Thus, the statement shows distributable income, defined
as income of the Trust available for distribution to the Trust unitholders before application of those unitholders’ additional expenses,
if any, for depreciation, depletion, and amortization, interest and income taxes. The revenues are reflected net of existing royalties
and overriding royalties and have been reduced by gathering/post-production expenses.
Revenue and Expenses:
The Trust serves as a pass-through entity, with
items of depletion, interest income and expense, and income tax attributes being based upon the status and election of the unitholders.
Thus, the Statements of Distributable Income show income available for distribution before application of those unitholders’ additional
expenses, if any, for depletion, interest income and expense, and income taxes.
The Trust uses the accrual basis to recognize revenue,
with royalty income recorded as reserves are extracted from the Underlying Properties and sold. Expenses are recognized when paid.
Royalty Interest in Gas Properties:
The
Royalty interest in gas properties is assessed to determine whether the net capitalized cost is impaired, whenever events or changes in
circumstances indicate that its carrying amount may not be recoverable, pursuant to ASC Topic 360, Property, Plant and Equipment.
The Trust determines whether an impairment charge is necessary to its investment in the Royalty interest in gas properties if total capitalized
costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties.
Determination as to whether and how much an asset is impaired involves estimates of fair value, which is determined based on discounted
cash flow techniques using assumptions including projected revenues, future commodity prices, production costs, and market-specific average
cost of capital. Estimates of undiscounted future net revenues attributable to proved gas reserves utilize estimates of future pricing,
which are generally developed based upon NYMEX forward pricing curves. If required, the Trust will recognize an impairment charge to the
extent that the net capitalized costs exceed the discounted fair value of the investment in net profits interests attributable to proved
gas reserves of the Underlying Properties. Any such impairment charge would not reduce Distributable Income, although it would reduce
Trust Corpus. No impairment in the Underlying Properties was recognized during the quarter ended June 30, 2022. Significant dispositions
or abandonment of the Underlying Properties are charged to Royalty Interests and the Trust Corpus.
Amortization of the Royalty interest in gas properties
is calculated on a units-of-production basis, whereby the Trust’s cost basis in the properties is divided by Trust total proved
reserves to derive an amortization rate per reserve unit. Such amortization does not reduce Distributable Income, rather it is charged
directly to Trust Corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant
revisions are known.
The conveyance of the Royalty Interests to the Trust
was accounted for as a purchase transaction. The $352,100,000 reflected in the Statements of Assets, Liabilities and Trust Corpus as Royalty
interest in gas properties represents 17,605,000 Trust units valued at $20.00 per unit. The carrying value of the Trust’s investment
in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.