Item 1. Business
Introduction
ECA Marcellus Trust I is a statutory trust formed in March 2010 under the Delaware Statutory Trust Act, pursuant to a Trust Agreement, as amended and restated (the "Trust Agreement"), among Energy Corporation of America ("Legacy ECA"), as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the "Trustee"), and Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee"). The Trust maintains its offices at the office of the Trustee, at 601 Travis Street, 16th Floor, Houston Texas 77002. The telephone number of the Trustee is 1-512-236-6555.
In November 2017, Greylock Energy, LLC, and certain of its wholly owned subsidiaries ("Greylock") acquired substantially all of the gas production and midstream assets of Legacy ECA, including all of Legacy ECA's interests in certain natural gas properties that are subject to royalty interests held by the Trust (the "Acquisition").
In connection with the Acquisition, Greylock assumed all of Legacy ECA's obligations under the Amended and Restated Trust Agreement among the Trust, Legacy ECA and the Trustee, and other instruments to which Legacy ECA and the Trustee are parties, including (1) the Administrative Services Agreement by and among Legacy ECA, the Trust and the Trustee dated July 7, 2010, and (2) a letter agreement between Legacy ECA and the Trustee regarding certain loans to be made by Legacy ECA to the Trust as necessary to enable the Trust to pay its liabilities as they become due (the "Letter Agreement"). In addition, Legacy ECA, Greylock, and the Trustee entered into a Reaffirmation and Amendment of Mortgage, Assignment of Leases, Security Agreement, Fixture Filing and Financing Statement (the "Reaffirmation Agreement"), pursuant to which, among other things, Greylock (1) reaffirmed the liens and the security interest granted pursuant to the existing mortgage securing the interests in the subject properties, as well as the mortgage and the obligations of Legacy ECA under the mortgage, and (2) assumed the obligations of Legacy ECA under the Letter Agreement.
The Trust makes copies of its reports under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), available at www.businesswire.com/cnn/ect.htm. The Trust's filings under the Exchange Act are also available electronically from the website maintained by the SEC at http://www.sec.gov. The Trust will also provide electronic and paper copies of its filings free of charge upon request to the Trustee.
General
The Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Royalty Interests (described below), to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalty Interests after the payment of Trust expenses, and to perform certain administrative functions in respect of the Royalty Interests and the Trust units. The Trustee has no authority or responsibility for, and no involvement with, any aspect of the oil and gas operations on the properties to which the Royalty Interests relate. The Trust derives all or substantially all of its income and cash flows from the Royalty Interests. The Trust is treated as a partnership for federal and state income tax purposes.
Initially, the Trust owned royalty interests in the 14 Producing Wells described in the Prospectus (the "Producing Wells") and royalty interests in 52 horizontal natural gas development wells to be drilled to the Marcellus Shale formation (the "PUD Wells") within the AMI, in which Legacy ECA held approximately 9,300 acres, of which it owned substantially all of the working interests, in Greene County, Pennsylvania. The AMI consisted of the Marcellus Shale formation in approximately 121 square miles in Greene County, Pennsylvania.
Legacy ECA completed its drilling obligation to the Trust under the Development Agreement as of November 30, 2011, approximately 2.3 years in advance of the required completion date of March 31, 2014. Consequently, no additional wells have been or will be drilled for the Trust. As of December 31, 2017 the Trust owns Royalty Interests in the 14 Producing Wells and the 40 development wells (52.06 Equivalent PUD Wells) that are now completed and in production. The 14 Producing Wells and the 40 development wells (52.06 Equivalent PUD Wells) are sometimes herein called the "Trust Wells".
The royalty interests were conveyed from Legacy ECA's working interest in the Producing Wells and the PUD Wells limited to the Marcellus Shale formation (the "Underlying Properties"). The royalty interest in the Producing Wells (the "PDP Royalty Interest") entitles the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to Legacy ECA's interest in the Producing Wells for a period of 20 years commencing on April 1, 2010 and 45% thereafter. The royalty interest in the PUD Wells (the "PUD Royalty Interest" and together with the PDP Royalty Interest, the "Royalty Interests") entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to Legacy ECA's interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter. As used herein, the term "Producing Wells" means the 14 Producing Wells as defined above, and does not include the 40 PUD Wells, although they also have been completed and are producing.
Legacy ECA was obligated to drill all of the PUD Wells no later than March 31, 2014. As of November 30, 2011, Legacy ECA had fulfilled its drilling obligation to the Trust by drilling 40 PUD Wells (52.06 Equivalent PUD Wells), calculated as provided in the Development Agreement. The Trust was not responsible for any costs related to the drilling of development wells or any other development or operating costs. The Trust's cash receipts in respect of the Royalty Interests is determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests, and the Trust's cash available for distribution includes any cash receipts from the hedge contracts and is reduced by Trust administrative expenses. Post-production costs generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Charges payable to Legacy ECA for such post-production costs on the related Greene County Gathering System (the "Post-Production Services Fee") were limited to $0.52 per MMBtu gathered until Legacy ECA fulfilled its drilling obligation in 2011; since then Legacy ECA was, and after the Acquisition Greylock is, permitted to increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System.
Generally, the percentage of production proceeds to be received by the Trust with respect to a well equals the product of (i) the percentage of proceeds to which the Trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) Legacy ECA's net revenue interest in the well. Legacy ECA on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the Trust is entitled to receive on average 73.37% of the proceeds of production from the Producing Wells. With respect to the PUD Wells, the conveyance related to the PUD Royalty Interest provides that the proceeds from the PUD Wells are calculated on the basis that the underlying PUD Wells are burdened only by interests that in total would not exceed 12.5% of the revenues from such properties, regardless of whether the royalty interest owners are actually entitled to a greater percentage of revenues from such properties. As an example, assuming Legacy ECA owns a 100% working interest in a PUD Well, the applicable net revenue interest is calculated by multiplying Legacy ECA's percentage working interest in the 100% working interest well by the unburdened interest percentage (87.5%) and such well would have a minimum 87.5% net revenue interest. Accordingly, the Trust is entitled to a minimum of 43.75% of the production proceeds from the well provided in this example. To the extent Legacy ECA's working interest in a PUD Well is less than 100%, the Trust's share of proceeds would be proportionately reduced.
As described under "-Duration of the Trust; Sale of Royalty Interests" below, the Trust is required to dissolve if the gross proceeds received by the Trust attributable to the Royalty Interests over any four consecutive quarters are less than $1.5 million. Gross proceeds over the four consecutive quarters ended December 31, 2017 were $6.9 million.
Historical Target Distributions
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting Trust administrative expenses, including the costs incurred as a result of being a publicly traded entity, on or about the 60th day following the completion of each quarter. Unless it is sooner liquidated, the Trust will liquidate on or about March 31, 2030.
The amount of Trust revenues and cash distributions to Trust unitholders depend on, among other things:
• natural gas prices received;
• the volume and Btu rating of natural gas produced and sold;
• post-production costs and any applicable taxes;
• administrative expenses of the Trust including expenses incurred as a result of being a publicly traded entity, and any changes in amounts reserved for such expenses; and
• through March 31, 2014, the effects of the hedge arrangements.
The effective date of the Trust was April 1, 2010, meaning the Trust has received the proceeds of production attributable to the PDP Royalty Interest from that date even though the PDP Royalty Interest was not conveyed to the Trust until July 7, 2010. The amount of the quarterly distributions fluctuates from quarter to quarter, depending on the proceeds received by the Trust, among other factors. There is no minimum required distribution.
Pursuant to IRC Section 1446, withholding tax on income effectively connected to a United States trade or business allocated to foreign partners ("ECI") should be made at the highest marginal rate. Under IRC Section 1441, withholding tax on fixed, determinable, annual, periodic income from United States sources allocated to foreign partners should be made at 30% of gross income unless the rate is reduced by treaty. This release is intended to be a qualified notice to nominees and brokers as provided for under Treasury Regulation Section 1.1446-4(b) by ECA Marcellus Trust I, and while specific relief is not specified for Section 1441 income, this disclosure is intended to suffice. Nominees and brokers should withhold 39.6% of the distribution made to foreign partners. The recently enacted Tax Cuts and Jobs Act treats a non-U.S. holder's gain on the sale of Trust units as ECI to the extent such holder would have had ECI if the Trust had sold all of its assets at fair market value on the date of the exchange. The new legislation also requires the transferee of units to withhold 10% of the amount realized on the sale of exchange of units (generally, the purchase price) unless the transferor certifies that it is not a nonresident alien individual or foreign corporation.
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting Trust administrative expenses, including the costs incurred as a result of being a publicly traded entity, on or about the 60th day following the completion of each quarter. Unless sooner liquidated, as discussed in detail below under the caption "The Trustee may, under certain circumstances, sell the Royalty Interests and dissolve the Trust. Unless sooner terminated, the Trust will begin to terminate following the end of the 20 year period in which the Trust owns the Term Royalty Interests" in Item 1A.
Item 1A. Risk Factors
Natural gas prices fluctuate due to a number of factors that are beyond the control of the Trust and Greylock, and lower prices would reduce proceeds to the Trust and cash distributions to unitholders.
The Trust's reserves and quarterly cash distributions are highly dependent upon the prices realized from the sale of natural gas. Natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and Greylock. These factors include, among others:
• weather conditions and seasonal trends;
• regional, domestic and foreign supply and perceptions of supply of natural gas;
• availability of imported liquefied natural gas, or LNG;
• 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;
• the price and availability of alternative fuels;
• 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.
Lower natural gas prices will reduce proceeds to which the Trust is entitled and may ultimately reduce the amount of natural gas that is economic to produce from the Underlying Properties. As a result, the operator of any of the Underlying Properties could determine during periods of low natural gas prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operator of the Underlying Properties could determine during periods of low natural gas prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, Greylock may abandon any well or property if it reasonably believes that the well or property can no longer produce natural gas in commercially economic quantities. This could result in termination of the portion of the royalty interest relating to the abandoned well or property, and Greylock would have no obligation to drill a replacement well. In making such decisions, Greylock is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as burdens affecting such property. The volatility of natural gas prices also reduces the accuracy of estimates of future cash distributions to Trust unitholders.
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.
The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the reserves estimated to be attributable to the Trust's Royalty Interests. The Trust's reserve quantities and revenues are based on estimates of reserve quantities and revenues for the Underlying Properties. See "The underlying properties-Natural gas reserves" in the Prospectus for a discussion of the method of allocating Proved reserves to the Trust. It is not possible to measure underground accumulations of natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary negatively and in material amounts from estimates and those variations could be material. Petroleum engineers are required to make subjective estimates of underground accumulations of natural gas based on factors and assumptions that include:
• 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; 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.
Further, the reserve report estimating the Trust's proved reserves, future production and income attributable to the Trust's Royalty Interests as of December 31, 2017 was prepared, in accordance with applicable regulations, using a weighted benchmark price adjusted for differentials resulting in an average natural gas price of $2.63 per Mcf during 2017, as described in Appendix A to this report. At the date of this report, the weighted benchmark natural gas price, adjusted for differentials, for production in which the Trust has an interest is below $2.63. A reserve report prepared using the current lower value would result in lower proved reserves, future production and income attributable to the Trust's Royalty Interests.
The generation of proceeds for distribution by the Trust depends in part on gathering, transportation and processing facilities owned by Greylock and others. Any limitation in the availability of those facilities could interfere with sales of natural gas production from the Underlying Properties.
The amount of natural gas that may be produced and sold from any well to which the Underlying Properties relate is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery of gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, Greylock is provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If Greylock is forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced due to the reduction of proceeds from the sale of production.
The generation of proceeds for distribution by the Trust depends in part on the ability of Greylock and/or its customers to obtain service on transportation facilities owned by third party pipelines. Any limitation in the availability of those facilities and/or any increase in the cost of service on those facilities could interfere with sales of natural gas production from the Underlying Properties.
Natural gas that is gathered on the Greene County Gathering System, including natural gas produced from the Underlying Properties, is currently shipped on two interstate natural gas transportation pipelines. Greylock or its purchasers have contracted with those pipelines for firm or interruptible transportation service. The rates for service on the transportation pipelines are regulated by the FERC and are subject to increase if the pipeline demonstrates that the existing rates are unjust and unreasonable.
Greylock has an agreement with Columbia to provide firm transportation downstream of Greylock's Greene County Gathering System for 50,000 MMBtu per day. This firm transportation arrangement, which terminates July 31, 2021, has been in effect since August 1, 2011 and is at Columbia's filed tariff rate, which is currently $0.1878 per MMBtu at a one hundred percent load factor. This firm transportation is an additional post-production cost, and the Trust bears its proportionate share of such costs.
In the future, Greylock may seek to obtain additional firm transportation capacity, but such capacity may not be available. In addition, to the extent Greylock's customers or Greylock became dependent on interruptible service, and to the extent that either pipeline receives requests for service that exceed the capacity of the pipeline, the pipeline will honor requests by its firm customers first, and will then allocate remaining capacity, if any, to interruptible shippers. As a result, Greylock or its customers may be unable to obtain all or a part of any requested interruptible capacity service on the transportation pipelines. Any inability of Greylock or its customers to procure sufficient capacity to
transport the natural gas gathered on the Greene County Gathering System will decrease and/or delay the receipt of any proceeds that may be associated with natural gas production from wells on the Underlying Properties. In addition, any increase in transportation rates paid by Greylock for production attributable to the Trust's interests will decrease the proceeds received by the Trust.
Due to the Trust's lack of industry and geographic diversification, adverse developments in the Trust's existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.
The Underlying Properties are operated for natural gas production only and are focused exclusively in the Marcellus Shale formation in Greene County, Pennsylvania. In particular, the concentration of the Underlying Properties in the Marcellus Shale formation in Greene County could disproportionately expose the Trust's interests to operational and regulatory risk in that area. Due to the lack of diversification in industry type and location of the Trust's interests, adverse developments in the natural gas market or the area of the Underlying Properties could have a significantly greater impact on the Trust's financial condition, results of operations and cash flows than if the Trust's Royalty Interests were more diversified.
The Trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.
The existence of a material title deficiency with respect to the Underlying Properties can reduce the value or render a property worthless, thus adversely affecting the distributions to unitholders. Greylock does not obtain title insurance covering mineral leaseholds. Additionally, undeveloped acreage has greater risk of title defects than developed acreage.
Prior to the drilling of the PUD Wells, Legacy ECA obtained preliminary title reviews to ensure there were no obvious defects in title to the leasehold. However, a title review is not title insurance, and in the event of a material title problem in the future, proceeds available for distribution to unitholders, and the value of the Trust units, may be reduced.
The Trust is passive in nature and has no stockholder voting rights in Greylock, managerial, contractual or other ability to influence Greylock, or control over the field operations of, sale of natural gas from, or development of, the Underlying Properties.
Neither the Trust nor the Trust unitholders has any voting rights with respect to Greylock and therefore none of them has any managerial, contractual or other ability to influence Greylock's activities or operations of the natural gas properties. This is how, pursuant to the Administrative Services Agreement and the Development Agreement, Legacy ECA was able to transfer operations of all of the Trust properties to Greylock, who also retains the right to transfer operations of any or all of the Trust properties. Any third-party operators may not have the operational expertise of Greylock within the AMI. Natural gas properties are typically managed pursuant to an operating agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders has any contractual ability to influence or control the field operations of, sale of natural gas from, or any future development of, the Underlying Properties. The Trust units are a passive investment that entitles the Trust only to receive cash distributions attributable to the Royalty Interests.
Greylock may sell all or a portion of the Underlying Properties, subject to and burdened by the Royalty Interests, and any such purchaser could have a weaker financial position and/or be less experienced in natural gas development and production than Greylock.
Trust unitholders will not be entitled to vote on any sale of the Underlying Properties if the Underlying Properties are sold subject to and burdened by the Royalty Interests and the Trust will not receive any proceeds from any such sale. The purchaser would be responsible for all of Greylock's obligations relating to the Royalty Interests on the portion of the Underlying Properties sold, and Greylock would have no continuing obligation to the Trust for those properties. Additionally, Greylock may enter into farmout or joint venture arrangements with respect to the wells burdened by the Royalty Interests. Any purchaser, farmout counterparty or joint venture partner could have a weaker financial position and/or be less experienced in natural gas development and production than Greylock.
The natural gas reserves estimated to be attributable to the Underlying Properties of the Trust are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and gas properties or Royalty Interests to replace the depleting assets and production.
The proceeds payable to the Trust from the Royalty Interests are derived from the sale of the production of natural gas from the Underlying Properties. The natural gas reserves attributable to the Underlying Properties are depleting assets, which means that the reserves of natural gas attributable to the Underlying Properties will decline over time. As a result, the quantity of natural gas produced from the Underlying Properties will decline over time. Based on the estimated production volumes in the original reserve report described in the Prospectus, the gas production from proved producing reserves attributable to the PDP Royalty Interest was projected to decline at an average rate of approximately 8.5% per year over the life of the Trust. With respect to the PUD Wells, as of the Trust formation date, the production rate was expected to decline approximately 37.3% during the first year of production, approximately 14.7% during the next three to five years of production and approximately 8.0% per year for the remainder of the economically productive life of the well. These production characteristics were generally consistent with other development wells in the AMI. The anticipated rate of decline as originally projected was an estimate and actual decline rates may vary from those estimates. The average decline rate for the 40 PUD Wells for which Greylock now has several years of production data was about 43.5% during the first year.
Future maintenance may affect the quantity of Proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these projects will depend on, among other factors, the market prices of natural gas. Greylock has no contractual obligation to make capital expenditures on the Underlying Properties in the future. Furthermore, for properties on which Greylock is not designated as the operator, Greylock has no control over the timing or amount of those capital expenditures. Greylock also has the right to non-consent and not participate in the capital expenditures on properties for which it is not the operator, in which case Greylock and the Trust will not receive the production resulting from such capital expenditures. If Greylock or other operators of the wells to which the Underlying Properties relate do not implement maintenance projects when warranted, the future rate of production decline of Proved reserves may be higher than the rate currently expected by Greylock or estimated in the reserve report.
The Trust Agreement provides that the Trust's business activities are limited to owning the Royalty Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not permitted to acquire other oil and gas properties or royalty interests to replace the depleting assets and production attributable to the Trust.
The amount of cash available for distribution by the Trust will be reduced by the amount of post-production costs, applicable taxes associated with the Trust's interest, and Trust expenses.
The Royalty Interests and the Trust bear certain costs and expenses that reduce the amount of cash received by the Trust or available for distribution by the Trust to the holders of the Trust units. These costs and expenses include those described below.
• Substantially all of the production from the Producing Wells and the PUD Wells utilize the Greene County Gathering System. The Trust paid the initial Post-Production Services Fee to Legacy ECA for use of such system, which includes Legacy ECA's costs to gather, compress, transport, process, treat, dehydrate and market the gas. This fee was fixed until Legacy ECA's obligation to drill the PUD Wells was satisfied in 2011; thereafter, Legacy ECA was and Greylock is permitted to increase this fee to the extent necessary to recover certain capital expenditures on the Greene County Gathering System, provided 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 holders of the Trust units, including any amounts paid by Greylock for transportation on downstream interstate pipelines. Such post-production costs include the costs incurred in connection with Greylock's agreement with a third party to obtain firm transportation downstream of the Greene County Gathering System for 50,000 MMBtu per day at the third party's filed tariff rate, which equates to $0.1878 per MMBtu at a one hundred percent load factor. The rate is subject to adjustments, which may be retroactive, by regulatory authorities.
• 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, and 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.
• The Trust is also responsible for paying other expenses, including costs associated with annual and quarterly reports to 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 by which the costs and expenses described above are higher or lower in any quarter will directly decrease or increase the amount received by the Trust and available for distribution to the unitholders.
A decrease in the differential between the price realized by Greylock for natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of Trust units.
During the first few years of the Trust's existence, prices received for natural gas production from Trust properties exceeded the relevant benchmark prices, such as NYMEX; however, since 2014 the prices received have been lower than the benchmark prices, and this dynamic could continue in the future. The difference between the price received and the benchmark price is called a differential. The
differential may vary significantly due to market conditions, the quality and location of production and other factors. Greylock cannot accurately predict natural gas differentials. Further decreases in the differential between the realized price of natural gas and the benchmark price for natural gas could reduce the proceeds to the Trust and, accordingly, reduce the cash distributions by the Trust and the value of the Trust units.
The Trust has no hedges in place to protect against the price risk inherent in holding interest in natural gas, a commodity that is frequently characterized by significant price volatility.
At the formation of the Trust, approximately fifty percent of the estimated natural gas production attributable to the Royalty Interests was hedged from April 1, 2010 through March 31, 2014. From inception through the termination of the hedge arrangements, the Trust received approximately $35 million that it would not have received without the hedge arrangements. The last of the hedge arrangements expired March 31, 2014. Consequently, unitholders no longer have the benefit of any hedge arrangements, and all production is subject to the price risks inherent in holding interests in natural gas, a commodity that is frequently characterized by significant price volatility.
Natural gas wells are subject to operational hazards that can cause substantial losses. Greylock maintains insurance but may not be adequately insured for all such hazards.
There are a variety of operating risks inherent in natural gas production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blow-outs, uncontrollable flow of natural gas, water or drilling fluids, casing collapses, abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of natural gas at any of the Underlying Properties will reduce Trust distributions by reducing the amount of proceeds available for distribution.
Additionally, if any of such risks or similar accidents occur, Greylock could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If Greylock experiences any of these problems, its ability to conduct operations and perform its obligations to the Trust could be adversely affected. While Greylock maintains insurance coverage it deems appropriate for these risks with respect to the Underlying Properties, Greylock's operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance. If a well is damaged, Greylock would have no obligation to drill a replacement well or make the Trust whole for the loss. The Trust does not maintain any type of insurance against any of the risks of conducting oil and gas exploration and production or related activities.
The Trustee may, under certain circumstances, sell the Royalty Interests and dissolve the Trust. Unless sooner terminated, the Trust will begin to terminate following the end of the 20-year period in which the Trust owns the Term Royalty Interests.
The Trustee must sell the Royalty Interests if unitholders approve the sale or vote to dissolve the Trust. The Trustee must also sell the Royalty Interests if the gross proceeds to the Trust attributable to the Royalty Interests over any four consecutive quarters are less than $1.5 million. Sale of all the Royalty Interests will result in the dissolution of the Trust. The net proceeds of any such sale will be distributed to the Trust unitholders. Unless sooner terminated, the Trust will begin to liquidate on the Termination Date. The Trust unitholders will not be entitled to receive any proceeds from the sale of production from the Underlying Properties following such date. The Term Royalty Interests will automatically revert to Greylock at the Termination Date, while the Perpetual Royalty Interests will be sold and the proceeds will be distributed to the unitholders (including Greylock to the extent of any Trust units it owns) at the Termination Date or soon thereafter. Greylock has a right of first refusal to purchase the Perpetual Royalty Interests upon termination of the Trust.
If the Trust cannot meet the New York Stock Exchange continued listing requirements, the NYSE may delist the common units.
The Trust's common units are currently listed on the NYSE. In the future, if the Trust is unable to meet the continued listing requirements of the NYSE-which require, among other things, that the average closing price of the common units remain at or above $1.00 over 30 consecutive trading days-the common units could be delisted if the Trust is unable to regain compliance. A delisting of our common units could negatively impact the Trust by, among other things, reducing the liquidity and market price of the common units and reducing the number of investors willing to hold or acquire the common units.
The Private Investors may sell additional Trust units, and such sales could have an adverse effect on the trading price of the common units.
As of December 31, 2017, Greylock held no common units, while select Private Investors held common units. In connection with the Trust's formation, the Trust and the Private Investors entered into a registration rights agreement, pursuant to which the Trust in 2012 filed a registration statement on Form S-3, to facilitate sales of common units by such holders. If the Private Investors were to sell or offer to sell a substantial number of common units, the market price of the units could be adversely affected.
Conflicts of interest could arise between Greylock and the Trust unitholders.
As a working interest owner in the Underlying Properties, Greylock could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:
• Greylock'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 may abandon a well which is uneconomic to it while such well is still generating revenue for the Trust unitholders. Greylock 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 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 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's experience in the Marcellus Shale or its creditworthiness.
• Greylock 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 will be made only in connection with the sale by Greylock of the Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such Royalty Interests. See "Sale and Abandonment of Underlying Properties" in Item 2 of this report.
• Greylock may in its discretion increase its Post-Production Services Fee for post-production costs on the Greene County Gathering System to the extent necessary to recover certain capital expenditures on the Greene County Gathering System.
• Greylock 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 will deduct from the Trust's proceeds any charges under such contracts attributable to production from the Trust properties. Provisions in the conveyance agreements, however, require that charges under future contracts with affiliates of Greylock relating to processing or transportation of natural gas must be comparable to charges prevailing in the area for similar services.
• Greylock can purchase or sell Trust units without considering the effects the transaction may have on common unit prices or on the Trust itself. Additionally, Greylock 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, if any, at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it will be difficult for public unitholders to remove or replace the Trustee without the cooperation of Greylock (if at the time it holds a significant percentage of total Trust units) or other holders of a substantial percentage of the outstanding Trust units.
Trust unitholders have limited ability to enforce provisions of the Royalty Interests, and Greylock's liability to the Trust is limited.
The Trust Agreement permits the Trustee and the Trust to sue Greylock or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the PDP and PUD Royalty Interests. If the Trustee does not take appropriate action to enforce provisions of these conveyances, Trust unitholders' recourse would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust Agreement expressly limits a Trust unitholder's ability to directly sue Greylock or any other third party other than the Trustee. As a result, Trust unitholders will not be able to sue Greylock or any future owner of the Underlying Properties to enforce these rights. Furthermore, the Royalty Interest conveyances provide that, except as set forth in the conveyances, Greylock is not liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good faith.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of corporations under the General Corporation Law of the State of Delaware. Nevertheless, courts in jurisdictions outside of Delaware may not give effect to such limitation.
Greylock is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose Greylock to significant liabilities.
Greylock's natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these laws and regulations, Greylock must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive
reporting. Greylock may incur substantial costs in order to maintain compliance with these existing laws and regulations. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of natural gas and fluids as a result of drilling activities in the Marcellus Shale, there has been a variety of regulatory initiatives at the federal and state level to restrict oil and gas drilling operations in certain locations. Any increased regulation or suspension of oil and gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on Greylock's business, financial condition and results of operations. Greylock must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent Greylock is a shipper on interstate pipelines, it must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.
Laws and regulations governing natural gas exploration and production may also affect production levels. Greylock is required to comply with federal and state laws and regulations governing conservation matters, including provisions related to the unitization or pooling of the natural gas properties; the establishment of maximum rates of production from natural gas wells; the spacing of wells; the plugging and abandonment of wells; and removal of related production equipment. These and other laws and regulations can limit the amount of natural gas Greylock can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust's interests.
Pennsylvania historically has not imposed a severance tax on the production of natural gas. However, over the past few years there have been several proposals to initiate one. Most recently, in February 2016 the Governor of Pennsylvania proposed a flat 6.5 percent severance tax on the value of natural gas at the wellhead. Under the Governor's current proposal, the amount paid in impact fees paid on unconventional gas wells could be taken as a credit against the severance tax. Prior proposals included severance taxes of 5 percent, later reduced to 3.5 percent, plus 4.7 cents per thousand cubic feet of natural gas extracted. Any such severance tax, if adopted, would be a cost that would be borne by the Trust and could materially reduce distributions to unitholders.
New laws or regulations, or changes to existing laws or regulations, may unfavorably impact Greylock, could result in increased operating costs and have a material adverse effect on Greylock's financial condition and results of operations. For example, Congress has previously considered legislation that, if adopted in its proposed form, would subject companies involved in natural gas and oil exploration and production activities to, among other items the elimination of most U.S. federal tax incentives and deductions available to natural gas exploration and production activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. Additionally, the Pennsylvania Environmental Quality Board has proposed amendments to Pennsylvania's oil and gas regulations to update existing requirements regarding the drilling, casing, cementing, testing, monitoring and plugging of oil and gas wells, and the protection of water supplies, including reporting the list of chemicals used in hydraulic fracturing or to stimulate the well.
Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of Greylock and third party downstream natural gas transporters. These and other potential regulations could increase Greylock's operating costs, reduce Greylock's liquidity, delay Greylock's operations, increase direct and third party post production costs associated with the Trust's interests or otherwise alter the way Greylock conducts its business, which could have a material adverse effect on Greylock's financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid by Greylock for transportation on downstream interstate pipelines.
The ability of Greylock to satisfy its obligations to the Trust depends on the financial position of Greylock, and in the event of a default by Greylock in its obligations to the Trust, or in the event of Greylock's bankruptcy, it would be expensive and time-consuming for the Trust to exercise its remedies.
Greylock is a privately held, independent energy company engaged in the exploration, development, production, gathering and aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf Coast and Rocky Mountain regions in the United States. Greylock is also the operator of all of the Producing Wells and all of the PUD Wells. The conveyances also provide that Greylock is obligated to market, or cause to be marketed, the natural gas production related to the Underlying Properties. Due to the Trust's reliance on Greylock to fulfill these numerous obligations, the value of the Royalty Interests and its ultimate cash available for distribution will be highly dependent on Greylock's performance. Greylock is not a reporting company and does not file periodic reports with the SEC. Therefore, Trust unitholders do not have access to financial information of Greylock.
The ability of Greylock to perform its obligations to the Trust will depend on Greylock's future financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for natural gas and oil, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of Greylock.
Due to uncertainty under Pennsylvania law, the Royalty Interests conveyed by Greylock to the Trust might not be treated as real property interests, or as interests in hydrocarbons in place or to be produced. As a result, the Royalty Interests might be treated as unsecured claims of the Trust against Greylock in the event of Greylock's bankruptcy. The Royalty Interest Lien is intended to provide security to the Trust should the Royalty Interests be subject to such a challenge. If the PDP Royalty Interest or the PUD Royalty Interest were determined not to be a real property interest owned by the Trust, the Trust's remedy would be to foreclose on the Trust's Royalty Interest Lien to cause the Trust to receive a volume of natural gas production from the Trust properties calculated in accordance with the provisions of the conveyances of the Royalty Interests to the Trust. Foreclosure on the Royalty Interest Lien is exercisable only following a bankruptcy filing of Greylock or its successor and based on an uncured payment default occurring under the conveyances of the Royalty Interests to the Trust existing at the time of, or occurring after, such bankruptcy filing. The process of foreclosing to enforce the Royalty Interest Lien would be expensive and time-consuming, and the resulting delays and expenses could reduce Trust distributions substantially or eliminate them for an unpredictable period of time.
The proceeds of the Royalty Interests may be commingled, for a period of time, with proceeds of Greylock's retained interest. The Trust may not have adequate facts to trace its entitlement to funds in the commingled pool of funds and that other persons may, in asserting claims against Greylock's retained interest, be able to assert claims to the proceeds that should be delivered to the Trust. In addition, during a bankruptcy of Greylock, payments of the royalties may be delayed or deferred; in addition, the obligation to pay royalties may be disaffirmed or cancelled. In either situation, the Trust may need to look to the Royalty Interest Lien to replace its rights under the Royalty Interests. During the pendency of any bankruptcy proceedings involving Greylock, the Trust's ability to foreclose on the Royalty Interest Lien, and the ability to collect cash payments from customers being held in Greylock's accounts that are attributable to production from the Trust properties, may be stayed by the bankruptcy court. Delay in realizing on the collateral for the Royalty Interest Lien is possible, and a bankruptcy court might not permit such foreclosure. The bankruptcy also might delay the execution of a new agreement with another driller or operator. If the Trust were to enter into a new agreement with a drilling or operating partner, the new partner might not achieve the same levels of production or sell natural gas at the same prices as Greylock was able to achieve.
The operations of Greylock are subject to environmental laws and regulations that may result in significant costs and liabilities.
The natural gas exploration and production operations of Greylock in the Marcellus Shale are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge, emission or release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to Greylock's operations including the acquisition of a permit before conducting drilling; water withdrawal or waste disposal operations; govern the amounts and types of substances that may be disposed or released into the environment; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas containing endangered or threatened species or their habitats; require investigatory and response actions to mitigate pollution conditions arising from Greylock's operations or attributable to former operations; and impose obligations to reclaim and abandon well sites, impoundments and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations and the issuance of orders enjoining some or all of Greylock's operations in affected areas.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of Greylock's operations due to its handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to its operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, Greylock could be subject to joint and several strict liabilities for the removal or remediation of previously released materials or property contamination regardless of whether Greylock was responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which Greylock's wells are drilled and facilities where Greylock's petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage or to recover some or all of the costs of the removal or remediation of released materials. In addition, the risk of accidental spills or releases could expose Greylock to significant liabilities that could have a material adverse effect on its financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require Greylock to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition. Greylock may not be able to recover some or any of these costs from insurance.
Climate change laws and regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the natural gas that Greylock produces while the physical effects of climate change could disrupt Greylock's production and cause Greylock to incur significant costs in preparing for or responding to those effects.
In December 2009, the EPA published its findings that emissions of GHGs present a danger to public health and the environment. These findings allow the agency to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that could trigger permit review for GHG emissions from certain stationary sources. Those regulations were challenged in federal court and the Supreme Court has upheld the EPA's authority to regulate GHG emissions from stationary sources, concluding sources that trigger air permitting requirements based on their traditional criteria pollutant emissions must include a limit for GHGs in their permit. The EPA has also issued regulations that require the establishment and reporting of an inventory of GHG emissions from specified stationary sources, including certain onshore oil and natural gas exploration, development and production facilities. In
October 2015, the EPA finalized its "Clean Power Plan" regulations under Section 111(d) of the Clean Air Act to limit GHG emissions from existing power plants. Several states, trade groups and companies have challenged the legality of the EPA's Section 111(d) rule for existing power plants in federal court. On February 9, 2016, the Supreme Court granted an emergency stay preventing EPA from implementing the Clean Power Plan until the D.C. Circuit issues a decision on the legality of the rule and disposition of a writ of certiorari, to the extent such a writ is sought. President Trump has publicly stated that it is a top priority of his administration to eliminate the Clean Power Plan. The EPA has finalized regulations that require control of methane emissions from new sources in the oil and gas industry and target ozone-forming pollutants from existing sources in areas that do not meet federal ozone health standards. The EPA has also issued several Information Collection Requests to industry seeking assistance in developing a program for regulating methane emissions from existing oil and gas sources as well.
At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to control or reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, Greylock's equipment and operations could require Greylock to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas that it produces. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on Greylock's assets and operations.
Tax Risks Related to the Trust's Common Units
The Trust's tax treatment depends on its status as a partnership for United States federal income tax purposes. At the inception of the Trust, the Trust received an opinion from tax counsel that the Trust will be treated as a partnership for United States federal income tax purposes. If the Internal Revenue Service were to treat the Trust as a corporation for United States federal income tax purposes, then its cash available for distribution to you would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the Trust units depends largely on the Trust being treated as a partnership for United States federal income tax purposes. At the inception of the Trust, Legacy ECA and the Trust received an opinion from tax counsel that the Trust would be treated as a partnership for United States federal income tax purposes. In order for the Trust to be treated as a partnership for United States federal income tax purposes, current law requires that 90% or more of our gross income for every taxable year consist of "qualifying income," as defined in Section 7704 of the Internal Revenue Code. The Trust may not meet this requirement or current law may change so as to cause, in either event, the Trust to be treated as a corporation for United States federal income tax purposes or otherwise subject the Trust to taxation as an entity. Although the Trust does not believe based upon its current activities that it is so treated, a change in current law could cause it to be treated as a corporation for United States federal income tax purposes or otherwise subject it to taxation as an entity. The Trust has not requested, and does not plan to request, a ruling from the Internal Revenue Service, which we referred to as the IRS, on this or any other tax matter affecting it.
If the Trust was treated as a corporation for United States federal income tax purposes, it would pay United States federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 21%, and would likely be required to pay state income tax. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon the Trust as a corporation, its cash available for distribution to you would be substantially reduced. Therefore, treatment of the Trust as a
corporation would result in a material reduction in the anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of the Trust units.
The Trust Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to taxation as a corporation or otherwise subjects it to entity-level taxation for United States federal income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law on the Trust.
If the Trust were subjected to a material amount of additional entity-level taxation by Pennsylvania or any other states, the Trust's cash available for distribution to you would be reduced.
The Trust was historically required to pay Pennsylvania franchise tax on its capital stock value, as determined pursuant to the statute and apportioned to Pennsylvania. The tax rate of 0.045% was completely phased out effective January 1, 2016, though it could be readopted by the General Assembly in its annual budget process. Changes in current state law may subject the Trust to additional entity-level taxation by Pennsylvania or other states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any additional taxes on the Trust may substantially reduce the cash available for distribution to you and, therefore, negatively impact the value of an investment in the Trust units.
If enacted, severance taxes in Pennsylvania could materially increase the applicable taxes that are borne by the Trust.
Although Pennsylvania historically has not imposed a severance tax on the production of natural gas, in February 2016 the Governor of Pennsylvania proposed a flat 6.5 percent severance tax on the value of natural gas at the wellhead. Under the Governor's current proposal, the amount paid in impact fees paid on unconventional gas wells could be taken as a credit against the severance tax. Prior proposals included severance taxes of 5 percent, later reduced to 3.5 percent, plus 4.7 cents per thousand cubic feet of natural gas extracted. Any such severance tax, if adopted, would be a cost that would be borne by the Trust and could materially reduce distributions to unitholders.
The tax treatment of publicly traded partnerships or an investment in our Trust units could be affected by recent and potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The current United States federal income tax treatment of publicly traded partnerships, including the Trust, or an investment in the Trust units, may be modified by administrative, legislative or judicial interpretation at any time. In the past, Congress has considered substantive changes to the existing United States federal income tax laws that affect certain publicly traded partnerships. Any modification to the United States federal income tax laws or interpretations thereof could cause the Trust to be taxed as a corporation or make it difficult or impossible to meet the requirements for the Trust to be treated as a partnership for United States federal income tax purposes, affect or cause us to change our business activities, affect the tax considerations of an investment in the Trust, change the character or treatment of portions of the Trust income and adversely affect an investment in the Trust's units. Moreover, any modification to the United States federal income tax laws and interpretations thereof may or may not be applied retroactively. Any potential change in law or interpretation thereof could negatively impact the value of an investment in the Trust units.
Under current law for the taxable year ending December 31, 2017, the highest marginal United States federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal United States federal income tax rate applicable to long-term capital gains (generally, capital
gains on certain assets held for more than 12 months) of individuals is 20%. These rates are subject to change by new legislation at any time.
In addition, a 3.8% Medicare tax is imposed on certain net investment income from a variety of sources earned by individuals. For these purposes, net investment income generally includes a Trust unitholder's allocable share of the Trust income and gain realized by a Trust unitholder from a sale of the Trust units. The tax will be imposed on the lesser of (i) the Trust unitholder's net income from all investments, or (ii) the amount by which the Trust unitholder's adjusted gross income exceeds $250,000 (if the Trust unitholder is married and filing jointly) or $200,000 (if the Trust unitholder is unmarried).
Recently enacted federal legislation applicable to the Trust for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting income taxes due (including applicable penalties and interest) as a result of an audit. Unless the Trust is eligible to (and chooses to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect income taxes (including any applicable penalties and interest) directly from the Trust in the year in which the audit is completed under the new rules. If the Trust is required to pay income taxes, penalties and interest as the result of audit adjustments, cash available for distribution to Trust unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, Trust unitholders during that taxable year would bear the expense of the adjustment even if they were not Trust unitholders during the audited taxable year.
The Trust prorates items of income, gain, loss and deduction between transferors and transferees of the Trust units each month based upon the ownership of the Trust units on the first day of each month, instead of on the basis of the date a particular unit is transferred.
The Trust prorates items of income, gain, loss and deduction between transferors and transferees of the Trust units each month based upon the ownership of the Trust units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, the Trust's counsel was unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among the Trust unitholders. If the IRS contests the federal income tax positions the Trust takes, the market for the Trust units may be adversely impacted, the cost of any IRS contest will reduce the Trust's cash available for distribution to you and items of income, gain, loss and deduction may be reallocated among Trust unitholders.
If the IRS contests the United States federal income tax positions the Trust takes, the market for the Trust units may be adversely impacted and the cost of any IRS contest will reduce the Trust's cash available for distribution to you.
The Trust has not requested a ruling from the IRS with respect to its treatment as a partnership for United States federal income tax purposes or any other matter affecting the Trust. The IRS may adopt positions that differ from the conclusions of the Trust's counsel expressed in the Prospectus or from the positions the Trust takes. It may be necessary to resort to administrative or court proceedings to attempt to sustain some or all of the conclusions of the Trust's counsel or the positions the Trust takes. A court may not agree with some or all of the conclusions of the Trust's counsel or positions the Trust takes. Any contest with the IRS may materially and adversely impact the market for the Trust units and the price at which they trade. In addition, the Trust's costs of any contest with the IRS will be borne indirectly by the Trust unitholders because the costs will reduce the Trust's cash available for distribution.
You will be required to pay taxes on your share of the Trust's income even if you do not receive any cash distributions from the Trust.
Because the Trust unitholders will be treated as partners to whom the Trust will allocate taxable income which could be different in amount than the cash the Trust distributes, you will be required to pay any United States federal income taxes and, in some cases, state and local income taxes on your share of the Trust's taxable income even if you receive no cash distributions from the Trust. You may not receive cash distributions from the Trust equal to your share of the Trust's taxable income or even equal to the actual tax liability that result from that income.
Tax gain or loss on the disposition of the Trust units could be more or less than expected.
If you sell your Trust units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those Trust units. Because distributions in excess of your allocable share of the Trust's net taxable income decrease your tax basis in your Trust units, the amount, if any, of such prior excess distributions with respect to the Trust units you sell will, in effect, become taxable income to you if you sell such Trust units at a price greater than your tax basis in those Trust units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion recapture.
Tax-exempt entities and non-United States persons face unique tax issues from owning the Trust units that may result in adverse tax consequences to them.
Investment in Trust units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-United States persons raises issues unique to them. For example, some of the Trust income allocated to organizations exempt from United States federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income which would be taxable to them. Distributions to non-United States persons may be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons may be required to file United States federal income tax returns and pay tax on their share of the Trust's taxable income.
The Trust will treat each purchaser of Trust units as having the same economic attributes without regard to the actual Trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.
Due to a number of factors, including the Trust's inability to match transferors and transferees of Trust units, the Trust will adopt positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of Trust units and could have a negative impact on the value of the Trust units or result in audit adjustments to your tax returns.
A Trust unitholder whose Trust units are loaned to a "short seller" to cover a short sale of Trust units may be considered as having disposed of those Trust units. If so, he would no longer be treated for tax purposes as a partner with respect to those Trust units during the period of the loan and may recognize gain or loss from the disposition.
Because a Trust unitholder whose Trust units are loaned to a "short seller" to cover a short sale of Trust units may be considered as having disposed of the loaned Trust units, the Trust unitholder may no longer be treated for United States federal income tax purposes as a partner with respect to those Trust units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of the Trust's
income, gain, loss or deduction with respect to those Trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Trust units could be fully taxable as ordinary income. The Trust's counsel has not rendered an opinion regarding the treatment of a unitholder where Trust units are loaned to a short seller to cover a short sale of Trust units; therefore, Trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their Trust units.
The Trust will adopt certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the Trust unitholders. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.
The United States federal income tax consequences of the ownership and disposition of Trust units will depend in part on the Trust's estimates of the relative fair market values, and the initial tax bases of the Trust's assets. Although the Trust may from time to time consult with professional appraisers regarding valuation matters, the Trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Trust unitholders might change, and Trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments. It also could affect the amount of gain from unitholders' sale of Trust units and could have a negative impact on the value of the Trust units or result in audit adjustments to unitholders' tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of the Trust's capital and profits interests during any twelve-month period will result in the termination of the Trust's partnership status for United States federal income tax purposes.
The Trust will be considered to have technically terminated for United States federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same Trust unit within any twelve-month period will be counted only once. The Trust's termination would, among other things, result in the closing of its taxable year for all Trust unitholders, which would result in the Trust filing two tax returns (and the Trust unitholders could receive two Schedules K-1) for one calendar year. The IRS has previously announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs. In the case of a unitholder reporting on a taxable year other than a calendar year ending December 31, the closing of the Trust's taxable year may also result in more than twelve months of the Trust's taxable income being includable in his taxable income for the year of termination. A technical termination would not affect the Trust's classification as a partnership for United States federal income tax purposes, but instead, the Trust would be treated as a new partnership for tax purposes. If treated as a new partnership, the Trust must make new tax elections and could be subject to penalties if the Trust is unable to determine that a technical termination occurred.
Certain United States federal income tax preferences currently available with respect to natural gas production may be eliminated as a result of future legislation.
In recent years, the U.S. government's budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for U.S. production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and natural gas within the U.S. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
The Underlying Properties
The Underlying Properties consist of the working interests owned by Greylock and the Private Investors in the Marcellus Shale formation in Greene County, Pennsylvania arising under leases and farmout agreements related to properties from which the PDP Royalty Interest and the PUD Royalty Interest were conveyed. As of December 31, 2017, the total natural gas reserves attributable to the Trust interests were 38.2 Bcf. Greylock continues to be the operator of all of the wells subject to the Royalty Interests although it is not contractually obligated to the Trust to remain so. The reserves attributable to the Royalty Interests include the reserves that are expected to be produced from the Marcellus Shale formation (subject to the terms of the conveyances creating the Net Profits Interests) during the remaining portion of the 20-year period in which the Trust owns the Royalty Interests as well as the residual interest in the reserves that the Trust will sell on or shortly following the Termination Date.
Natural Gas Reserves
Ryder Scott estimated natural gas reserves attributable to the Royalty Interests as of December 31, 2017. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the estimates.
Proved reserves of the Royalty Interests. The following table sets forth, certain estimated Proved reserves, estimated future net cash flows and the discounted present value thereof attributable to the Royalty Interests, as of December 31, 2017, in each case derived from the Ryder Scott reserve report. The reserve report was prepared by Ryder Scott in accordance with criteria established by the SEC. In accordance with the SEC's rules, the reserves presented below were determined using the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2017 through December 31, 2017, without giving effect to any derivative transactions, and were held constant for the life of the properties. This yielded an average realized price for natural gas of $2.63 per Mcf. The net revenues attributable to the Trust's reserves are net of the Trust's obligation to reimburse Greylock for post-production costs. The reserves and cash flows attributable to the Trust's interests include only the reserves attributable to the Underlying Properties that are expected to be produced
within the remaining portion of the 20-year period in which the Trust owns the Royalty Interests as well as the residual interest in the reserves that the Trust will own on the Termination Date. A summary of the Ryder Scott reserve report dated January 18, 2018 is included as Appendix A to this report.
(1)The present values of future net cash flows for the Royalty Interests were determined using a discount rate of 10% per annum.
Information concerning historical changes in net Proved reserves attributable to the Royalty Interests, and the calculation of the standardized measure of discounted future net cash flows related thereto, is contained in the unaudited supplemental information contained elsewhere in this report. The Trust has not filed reserve estimates covering the Royalty Interests with any other federal authority or agency.
The Reserve Report
Technologies. The reserve report was prepared using decline curve analysis to determine the reserves of individual Producing Wells.
Internal Controls. Ryder Scott, the independent petroleum engineering consultant, estimated, in accordance with appropriate engineering, geologic, and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry, and definitions and guidelines established by the SEC, all of the proved reserve information in this report. These reserves estimation methods and techniques are widely taught in university petroleum curricula and throughout the industry's ongoing training programs. Although these appropriate engineering, geologic, and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry are based upon established scientific concepts, the application of such principles involves extensive judgment and is subject to changes in existing knowledge and technology, economic conditions and applicable statutory and regulatory provisions. These same industry wide applied techniques are used in determining our estimated reserve quantities. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Society of Petroleum Engineers' Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information. Greylock's internal control over its reserve reporting process is designed to result in accurate and reliable estimates in compliance with applicable regulations and guidance. Internal reserve preparation is performed by staff reservoir engineers and geoscientists before review by the Reservoir Engineering Manager. These individuals consult regularly with Ryder Scott during the reserve estimation process to review properties, assumptions, and any new data available. Additionally, Greylock's senior management reviewed and approved all Ryder Scott reserve reports contained herein.
Greylock's reserves are reviewed by the Reservoir Engineering Manager. The Reservoir Engineering Manager has a Bachelor of Science degree in Petroleum Engineering. She has over five years of oil and gas industry experience in Reservoir Engineering. During that time, she has focused on reserves estimates and economics.
Sale and Abandonment of Underlying Properties
Greylock and any transferee will have the right to abandon its interest in any well or property composing a portion of the Underlying Properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the potential conflict of interest between Greylock and the Trust in determining whether a well is capable of producing in commercially paying quantities, Greylock is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as a burden affecting such property.
Greylock generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Royalty Interests, without the consent of the Trust unitholders. In addition, Greylock may, without the consent of the Trust unitholders, require the Trust to release Royalty Interests with an aggregate value to the Trust not to exceed $5.0 million during any twelve-month period. These releases will be made only in connection with a sale by Greylock of the Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such Royalty Interests. Greylock operates all of the wells subject to the Royalty Interests although it is not contractually obligated to the Trust to continue as the operator. Any net sales proceeds paid to the Trust are distributable to Trust unitholders for the quarter in which they are received. Greylock has not identified for sale any of the Underlying Properties.
Title to Properties
The Underlying Properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect Greylock's rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the Trust's interests and in estimating the size and the value of the reserves attributable to the Royalty Interests.
Legacy ECA acquired its interests in the Underlying Properties through a variety of means, including through the acquisition of oil and gas leases by Legacy ECA directly from the mineral owner, through assignments of oil and gas leases to Legacy ECA by the lessee who originally obtained the leases from the mineral owner, through Farmout agreements that grant Legacy ECA the right to earn interests in the properties covered by such agreements by drilling wells, and through acquisitions of other oil and gas interests by Legacy ECA. These interests were all acquired by Greylock as part of the asset acquisition described in "-Introduction" above.
Greylock's interests in the natural gas properties composing the Underlying Properties are typically subject, in one degree or another, to one or more of the following:
• royalties and other burdens, express and implied, under gas leases;
• production payments and similar interests and other burdens created by Greylock 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 to reassign all or part of a property to a third party if Greylock 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 believes that the burdens and obligations affecting the Underlying Properties and the Royalty Interests are conventional in the industry for similar properties. Greylock also believes that the burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the value of the Royalty Interests.
Greylock believes that its title to the Underlying Properties, and the Trust's title to the Royalty Interests, is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material as to detract substantially from the use or value of such properties or Royalty Interests. Prior to drilling each PUD Well, Greylock obtained a preliminary title review to ensure there were no obvious defects in title to the well. Greylock conducted a more thorough title examination of the drill site tract prior to drilling any of the PUD Wells.
It is unclear under Pennsylvania law whether the Royalty Interests would be treated as real property interests. Nevertheless, Greylock has recorded the conveyances of the Royalty Interests in the real property records of Pennsylvania in accordance with local recording acts. Greylock also has granted to the Trust the Royalty Interest Lien to provide protection to the Trust, in the event of a bankruptcy of Greylock, against the risk that the Royalty Interests were not considered real property interests.
Description of the Royalty Interests
The Royalty Interests were conveyed to the Trust by Legacy ECA by means of conveyance instruments that have been recorded in the appropriate real property records in Greene County, Pennsylvania, where the natural gas properties to which the Underlying Properties relate are located. The PDP Royalty Interest burdens the existing working interests now owned by Greylock in the Producing Wells. Greylock has an average working interest of approximately 93% in these wells.
The PUD Royalty Interest initially burdened 50% of all of the interests of Legacy ECA in the Marcellus Shale formation in the AMI. Greylock's current interests in the natural gas properties to which the PUD Wells relate consist of an average working interest of 100%. The conveyance related to the PUD Royalty Interest, however, provided that the proceeds from the PUD Wells would be calculated on the basis that the PUD Wells were only burdened by interests that in total would not exceed 12.5%. If Greylock's interest in any of the wells subject to the PUD Royalty Interest is subject to burdens in excess of 12.5%, such burdens will be fully allocated against Greylock's retained interest in such well, the net effect of which is that the Trust will receive payments with respect to the PUD Royalty Interest as if the burdens affecting the PUD Wells were in total 12.5% (proportionately reduced).
Generally, the percentage of production proceeds received by the Trust with respect to a well equals the product of (i) the percentage of proceeds to which the Trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) Greylock's net revenue interest in the well. Greylock on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the Trust is entitled to receive on average 73.37% of the proceeds of production from the Producing Wells. With respect to the PUD Wells, the conveyance related to the PUD Royalty Interest provides that the proceeds from the PUD Wells will be calculated on the basis that the underlying PUD Wells are burdened only by interests that in total would not exceed 12.5% of the revenues from such properties, regardless of whether the royalty interest owners are actually entitled to a greater percentage of revenues from such properties. As an example, assuming Greylock owns a 100% working interest in a PUD Well, the applicable net revenue interest is
calculated by multiplying Greylock's percentage working interest in the 100% working interest well by the unburdened interest percentage (87.5%), and such well would have a minimum 87.5% net revenue interest. Accordingly, the Trust is entitled to a minimum of 43.75% of the production proceeds from the well provided in this example. To the extent Greylock's working interest in a PUD Well is less than 100%, the Trust's share of proceeds would be proportionately reduced.
PDP Royalty Interest. The conveyances creating the PDP Royalty Interest entitle the Trust to receive an amount of cash for each calendar quarter equal to 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of estimated natural gas production attributable to the Producing Wells regardless of whether such amounts have actually been received by Greylock from the purchases of the natural gas produced. Proceeds from the sale of natural gas production attributable to the Producing Wells in any calendar quarter means:
• the amount calculated based on estimated production volumes attributable to the Producing Wells;
in each case, after deducting the Trust's proportionate share of:
• any taxes 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 Legacy ECA for such post-production costs on the Greene County Gathering System were limited to $0.52 per MMBtu of natural gas gathered until Legacy ECA fulfilled its drilling obligation in 2011, after which Legacy ECA was and now Greylock is permitted to increase the Post-Production Service Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System. 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.
PUD Royalty Interest. The conveyance creating the PUD Royalty Interest entitles the Trust to receive an amount of cash for each calendar quarter equal to 50% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of estimated natural gas production attributable to the PUD Wells regardless of whether such amounts have actually been received by Greylock from the purchase of the natural gas produced. Proceeds from the sale of natural gas production, if any, attributable to the PUD Wells in any calendar quarter means:
• the amount calculated based on estimated production volumes attributable to the PUD Wells;
in each case after deducting the Trust's proportionate share of:
• any taxes 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 Legacy ECA for such post-production charges on the Greene County Gathering System were limited to $0.52 per MMBtu of gas gathered until Legacy ECA fulfilled its drilling obligation in 2011, after which
Legacy ECA was and now Greylock is permitted to increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System. 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'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'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 Greylock to the Trust would be treated as real property interests. Therefore, Greylock has granted to the Trust a lien (the "Royalty Interest Lien") to provide protection to the Trust, exercisable in the event of a bankruptcy of Greylock, against the risk that the Royalty Interests were not considered real property interests. More specifically, the Royalty Interest Lien is a lien in the Subject Interest and the Subject Gas, to the extent and only to the extent that such Subject Interest and Subject Gas pertains to Gas in, under and that may be produced, saved or sold from the Marcellus Shale formation from the wellbore of the Producing Wells and the PUD Wells, sufficient to cause the Trust to receive a volume of Trust Gas calculated in accordance with the provisions of the conveyances of the Royalty Interests.
The Royalty Interest Lien does not include Greylock's retained interest in the PUD and Producing Wells and the AMI or other interest of Greylock in the AMI, and Greylock has the right to lien, mortgage, sell or otherwise encumber the Greylock retained interest subject to the Royalty Interest Lien.
Greylock has recorded the conveyances of the Royalty Interests and a Mortgage/Fixture Filing in the real estate records of Greene County, Pennsylvania and has filed a corresponding UCC-1 Financing Statement in the Office of the Secretary of State of West Virginia and the Commonwealth of Pennsylvania.
The conveyances also provide that if Greylock's interest with respect to the PDP properties is greater than what was warranted to the Trust in the conveyances, Greylock will have the right to offset against amounts owed to the Trust, the difference between what the Trust actually receives from PDP Royalty Interest and what the Trust should have received from the PDP Royalty Interest had Greylock's interest been the amount warranted.
Additional Provisions
If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:
• 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 due to adjustments to prior calculations of proceeds or otherwise will reduce future amounts payable to the Trust until Greylock recovers the overpayments.
The conveyances generally permit Greylock to sell, without the consent or approval of the Trust unitholders, all or any part of its interest in the Underlying Properties, if the Underlying Properties are sold, subject to and burdened by the Royalty Interests. The Trust unitholders are not entitled to any proceeds of any sale of Greylock's interest in the Underlying Properties that remains subject to and burdened by the Royalty Interests. Following any such sale, the proceeds attributable to the transferred property will be calculated pursuant to the conveyances as described in this report, and paid by the purchaser or transferee to the Trust.
Greylock or any transferee of an Underlying Property will have the right to abandon any well or property if it reasonably believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. In making such decisions, Greylock or any transferee of an Underlying Property is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as burdens affecting such property. Upon termination of the lease, that portion of the Royalty Interests relating to the abandoned property will be extinguished.
Greylock may, without the consent of the Trust unitholders, require the Trust to release Royalty Interests with an aggregate value to the Trust up to $5.0 million during any twelve-month period. These releases will be made only in connection with a sale by Greylock of the Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such Royalty Interests.
Greylock must maintain books and records sufficient to determine the amounts payable for the Royalty Interests to the Trust. Quarterly and annually, Greylock must deliver to the Trustee a statement of the computation of the proceeds for each computation period as well as quarterly drilling and production results.
Item 3.
Item 3. Legal Proceedings.
None.
Item 4.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
The Trust units commenced trading on the New York Stock Exchange on July 1, 2010 under the symbol "ECT." The high and low closing sales prices per unit for each quarter in 2016 and 2017 were as follows:
At December 31, 2017, the 17,605,000 units outstanding were held by 29 unitholders of record.
Distributions
Each quarter, the Trustee determines the amount of funds available for distribution to the Trust unitholders, as described elsewhere in this report. Quarterly cash distributions during the term of the Trust are made by the Trustee generally no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 45th day following the end of each quarter (or the next succeeding business day). The table below presents, for each quarter of 2016 and 2017, the net cash proceeds, the Trust expenses, and the resulting distributable income per Trust unit (dollars in thousands, except distributable income per unit).
Subsequent to year end, on or before February 28, 2018, a distribution of $0.067 per unit was paid to Trust common unitholders owning Trust common units as of February 20, 2018.
Equity Compensation Plans
The Trust does not have any employees and does not maintain any equity compensation plans.
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities
There were no purchases of Trust units by the Trust or any affiliated purchaser during the fourth quarter of 2017.
Item 6.
Item 6. Selected Financial Data.
The following is a summary of net proceeds, distributable income, and distributable income per unit by quarter in 2013, 2014, 2015, 2016, and 2017 (all amounts in thousands except distributable income per common unit):
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
This document contains forward-looking statements, which describe current expectations or forecasts of future events. Please refer to "Forward-Looking Statements" which follows the Table of Contents of this report for an explanation of these types of statements and their limitations.
Results of Trust Operations
For the twelve months ended December 31, 2017 compared to twelve months ended December 31, 2016
Distributable income for the year ended December 31, 2017 increased to $5.7 million from $3.5 million for the year ended December 31, 2016. Compared to the year ended December 31, 2016, royalty income increased $2.1 million and general and administrative expenses decreased by $0.1 million. No cash reserves were withheld or released by the Trustee during the years ended December 31, 2017 and 2016.
Royalty income increased from $4.8 million for the year ended December 31, 2016 to $6.9 million for the year ended December 31, 2017, an increase of $2.1 million. This increase was due to an increase in the average realized price offset by a decrease in production.
The average price realized for the year ended December 31, 2017 increased $0.80 per Mcf to $1.90 per Mcf as compared to $1.10 for the year ended December 31, 2016. The increase in the average sales price for gas production was due in part to an increase in the weighted average monthly closing NYMEX price and in part to an increase to the average Basis. The average sales price, before post-production costs, increased from $1.82 per Mcf for the year ended December 31, 2016 to $2.61 per Mcf for the year ended December 31, 2017. This increase in price was primarily the result of an increase in the weighted average monthly closing NYMEX price for the current period to $3.11 per MMBtu compared to the year ended December 31, 2016 weighted average monthly closing NYMEX price of $2.45 per MMBtu, aided by a $0.10 per MMbtu increase in the average Basis to $(0.58) per MMbtu in the current period compared to the prior period Basis of $(0.68) per MMbtu.
Post-production costs consist of a post-production services fee together with a charge for electricity used in lieu of gas for compression on the gathering system and firm transportation charges on interstate gas pipelines and an additional gathering charge for system enhancements applicable to certain wells in an effort to increase production by reducing the high line pressure previously experienced by those wells. Overall, average post-production costs decreased slightly to $0.71 per Mcf for the year ended December 31, 2017 as compared to $0.72 per Mcf for the year ended December 31, 2016. Post-production costs were slightly lower than the previous year primarily because of a slightly lower electricity usage charge per Mcf during the period due to a decline in production on the Greene County Gathering System.
Production decreased 16% from 4,319 MMcf for the year ended December 31, 2016 to 3,618 MMcf for the year ended December 31, 2017. The decreased production was primarily a result of natural production declines that occur during the life of a well.
General and administrative expenses paid by the Trust were $1.2 million for the year ended December 31, 2017, as compared to $1.3 million for the year ended December 31, 2016. During the year ended December 31, 2017, the decrease in expense resulted from lower professional services charges related to tax and advisory services.
For the twelve months ended December 31, 2016 compared to twelve months ended December 31, 2015
Distributable income for the year ended December 31, 2016 decreased to $3.5 million from $5.0 million for the year ended December 31, 2015. Compared to the year ended December 31, 2015, royalty income decreased $1.4 million and general and administrative expenses increased by $0.1 million. No cash reserves were withheld or released by the Trustee during the years ended December 31, 2016 and 2015.
Royalty income decreased from $6.2 million for the year ended December 31, 2015 to $4.8 million for the year ended December 31, 2016, a decrease of $1.4 million. This decrease was due to a decrease in the average realized price, a decrease in production, and an increase in post-production costs.
The average price realized for the year ended December 31, 2016 decreased $0.12 per Mcf to $1.13 per Mcf as compared to $1.25 for the year ended December 31, 2015. The decrease in the average sales price for gas production was due to a slight decrease in the weighted average monthly closing NYMEX price and by higher post-production costs, offset partially by an increase to the average Basis. The average sales price, before post-production costs, decreased from $1.91 per Mcf for the year ended December 31, 2015 to $1.85 per Mcf for the year ended December 31, 2016. This decrease in price was primarily the result of a decrease in the weighted average monthly closing NYMEX price for the current period to $2.45 per MMBtu compared to the year ended December 31,
weighted average monthly closing NYMEX price of $2.64 per MMBtu, partially offset by a $0.14 per MMbtu increase in the average Basis to $(0.67) per MMbtu in the current period compared to the prior period Basis of $(0.81) per MMbtu.
Post-production costs consist of a post-production services fee together with a charge for electricity used in lieu of gas for compression on the gathering system and firm transportation charges on interstate gas pipelines and an additional gathering charge for system enhancements applicable to certain wells in an effort to increase production by reducing the high line pressure previously experienced by those wells. Overall, average post-production costs increased slightly to $0.72 per Mcf for the year ended December 31, 2016 as compared to $0.66 per Mcf for the year ended December 31, 2015. Post-production costs were higher than the previous year primarily because of (1) a higher electricity usage charge per Mcf during the period due to a decline in production on the Greene County Gathering System and (2) higher firm transportation fees.
Production decreased 13% from 4,973 MMcf for the year ended December 31, 2015 to 4,319 MMcf for the year ended December 31, 2016. The decreased production was primarily a result of natural production declines that occur during the life of a well.
General and administrative expenses paid by the Trust were $1.3 million for the year ended December 31, 2016, as compared to $1.2 million for the year ended December 31, 2015. During the year ended December 31, 2016, the increase in expense resulted from an increase to the administrative fee paid to the Trustee, which was the result of the timing of billings in the current year.
Overview
The Trust is a statutory trust created under the Delaware Statutory Trust Act. The Bank of New York Mellon Trust Company, N.A. serves as Trustee. The Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Royalty Interests, to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalty Interests after payment of Trust expenses, and to perform certain administrative functions in respect of the Royalty Interests and the Trust units. The Trustee has no authority or responsibility for, and no involvement with, any aspect of the oil and gas operations on the properties to which the Royalty Interests relate. The Trust derives all or substantially all of its income and cash flows from the Royalty Interests. The Trust is treated as a partnership for federal and state income tax purposes.
In November 2017, Greylock Energy, LLC, and certain of its wholly owned subsidiaries ("Greylock") acquired substantially all of the gas production and midstream assets of Legacy ECA, including all of Legacy ECA's interests in certain natural gas properties that are subject to royalty interests held by the Trust.
In connection with the transaction, Greylock assumed all of Legacy ECA's obligations under the Amended and Restated Trust Agreement among the Trust, Legacy ECA and the Trustee, and other instruments to which Legacy ECA and the Trustee are parties, including (1) the Administrative Services Agreement by and among Legacy ECA, the Trust and the Trustee dated July 7, 2010, and (2) a letter agreement between Legacy ECA and the Trustee regarding certain loans to be made by Legacy ECA to the Trust as necessary to enable the Trust to pay its liabilities as they become due (the "Letter Agreement"). In addition, Legacy ECA, Greylock, and the Trustee entered into a Reaffirmation and Amendment of Mortgage, Assignment of Leases, Security Agreement, Fixture Filing and Financing Statement (the "Reaffirmation Agreement"), pursuant to which, among other things, Greylock (1) reaffirmed the liens and the security interest granted pursuant to the existing mortgage securing the interests in the subject properties, as well as the mortgage and the obligations of Legacy ECA under the mortgage, and (2) assumed the obligations of Legacy ECA under the Letter Agreement.
Legacy ECA completed its drilling obligation to the Trust under the Development Agreement as of November 30, 2011. Consequently, no additional wells will be drilled for the Trust. All trust units share in all cash distributions on a pro rata basis. As of December 31, 2017 the Trust owned Royalty Interests in the 14 Producing Wells and the 40 development wells (52.06 Equivalent PUD Wells calculated in accordance with the Development Agreement) that are now completed and in production.
The Royalty Interests were conveyed from Legacy ECA's working interest in the Producing Wells and the PUD Wells limited to the Underlying Properties. The PDP Royalty Interest entitles the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to Greylock's current interest in the Producing Wells for a period of 20 years commencing on April 1, 2010 and 45% thereafter. The PUD Royalty Interest entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to Greylock's current interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter. Approximately 50% of the originally estimated natural gas production attributable to the Royalty Interests was hedged through March 31, 2014.
Legacy ECA was obligated to drill all of the PUD Wells by March 31, 2014. As of November 30, 2011, Legacy ECA had fulfilled its drilling obligation to the Trust by drilling 40 PUD Wells (52.06 Equivalent PUD Wells), calculated as provided in the Development Agreement. The Trust was not responsible for any costs related to the drilling of development wells or any other development or operating costs. The Trust's cash receipts in respect of the Royalty Interests are determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests, and the Trust's cash available for distribution is reduced by Trust administrative expenses. Post-production costs generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Charges payable to Legacy ECA for such post-production costs on the related Greene County Gathering System were limited to $0.52 per MMBtu gathered until Legacy ECA fulfilled its drilling obligation in 2011; since then Legacy ECA was and Greylock is permitted to increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System.
Generally, the percentage of production proceeds to be received by the Trust with respect to a well equals the product of (i) the percentage of proceeds to which the Trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) Greylock's net revenue interest in the well. Greylock on average owns an 81.53% net revenue interest in the Producing Wells. Therefore, the Trust is entitled to receive on average 73.37% of the proceeds of production from the Producing Wells. With respect to the PUD Wells, the conveyance related to the PUD Royalty Interest provides that the proceeds from the PUD Wells will be calculated on the basis that the underlying PUD Wells are burdened only by interests that in total would not exceed 12.5% of the revenues from such properties, regardless of whether the royalty interest owners are actually entitled to a greater percentage of revenues from such properties. As an example, assuming Greylock owns a 100% working interest in a PUD Well, the applicable net revenue interest is calculated by multiplying Greylock's percentage working interest in the 100% working interest well by the unburdened interest percentage (87.5%), and such well would have a minimum 87.5% net revenue interest. Accordingly, the Trust is entitled to a minimum of 43.75% of the production proceeds from the well provided in this example. To the extent Greylock's working interest in a PUD Well is less than 100%, the Trust's share of proceeds would be proportionately reduced.
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting Trust administrative expenses and costs and reserves therefor, on or about 60 days following the completion of each quarter. Unless sooner terminated, the Trust will terminate in March 2030.
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;
• administrative expenses of the Trust including expenses incurred as a result of being a publicly traded entity, and any changes in amounts reserved for such expenses; and
• the effects of the hedge arrangements, and the expiration of the hedge arrangements.
The effective date of the Trust was April 1, 2010, meaning the Trust has received the proceeds of production attributable to the PDP Royalty Interest from that date even though the PDP Royalty Interest was not conveyed to the Trust until July 7, 2010. The amount of the quarterly distributions fluctuates from quarter to quarter, depending on the proceeds received by the Trust, among other factors. There is no minimum required distribution.
Pursuant to IRC Section 1446, withholding tax on income effectively connected to a United States trade or business allocated to foreign partners should be made at the highest marginal rate. Under Section 1441, withholding tax on fixed, determinable, annual, periodic income from United States sources allocated to foreign partners should be made at 30% of gross income unless the rate is reduced by treaty. This release is intended to be a qualified notice to nominees and brokers as provided for under Treasury Regulation Section 1.1446-4(b) by ECA Marcellus Trust I, and while specific relief is not specified for Section 1441 income, this disclosure is intended to suffice. Nominees and brokers should withhold 39.6% of the distribution made to foreign partners.
Liquidity and Capital Resources
The Trust has no source of liquidity or capital resources other than cash flows from the Royalty Interests. Other than Trust administrative expenses, including, if applicable, expense reimbursements to Greylock and any reserves established by the Trustee for future liabilities, the Trust's only use of cash is for distributions to Trust unitholders. Administrative expenses include payments to the Trustee and the Delaware Trustee as well as a quarterly fee of $15,000 to Greylock pursuant to the ASA. Each quarter, the Trustee determines the amount of funds available for distribution. Available funds are the excess cash, if any, received by the Trust from the Royalty Interests and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust's expenses for that quarter. Available funds are reduced by any cash the Trustee determines to hold as a reserve against future expenses or liabilities. The Trustee may borrow funds required to pay expenses or liabilities if the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust's expenses or liabilities. If the Trustee borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid.
Payments to the Trust in respect of the Royalty Interests are based on the complex provisions of the various conveyances held by the Trust, copies of which are filed as exhibits to this report, and reference is hereby made to the text of the conveyances for the actual calculations of amounts due to the Trust.
The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust's liquidity or the availability of capital resources.
Off-Balance Sheet Arrangements
The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.
Contractual Obligations
A summary of the Trust's contractual obligations as of December 31, 2017 is provided in the following table (in thousands):
Pursuant to the terms of the ASA, the Trust is obligated to pay Greylock an annual administrative services fee of $60,000 for accounting, bookkeeping and informational services relating to the Royalty Interests to be performed by Greylock on behalf of the Trust throughout the term of the Trust. Pursuant to the Trust Agreement, the Trustee is to be paid an annual administrative fee of $150,000, which may be adjusted annually, up or down, by the amount of the change in the All Urban Consumers (CPI-U)-US City Average for the immediately preceding calendar year, not to exceed +/- 3% in any one year. The Trust is also obligated to pay the Delaware Trustee a fee of $2,500 per year, throughout the term of the Trust.
Greylock and the Trustee each may terminate the provisions of the ASA relating to Greylock's provision of administrative services at any time following delivery of notice no less than 90 days prior to the date of termination; provided, however, that Greylock may not terminate the ASA except in connection with Greylock's transfer of some or all of the Subject Interests, as defined in the Conveyances, and then only with respect to the services to be provided with respect to the Subject Interests being transferred, and only upon the delivery to the Trustee of an agreement of the transferee of such Subject Interests reasonably satisfactory to the Trustee in which such transferee assumes the responsibility to perform the services relating to the Subject Interests being transferred.
Significant Accounting Policies
The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP") because certain cash reserves may be established for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. Amortization of the investment in overriding royalty interests calculated on a unit-of-production basis is charged directly to Trust Corpus. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by FASB ASC Topic 932 Extractive Activities-Oil and Gas: Financial Statements of Royalty Trusts.
Income determined on the basis of GAAP would include all expenses incurred for the period presented. However, the Trust serves as a pass-through entity, with expenses for depreciation, depletion, and amortization, interest and income taxes being based on the status and elections of the Trust unitholders. General and administrative expenses, production taxes or any other allowable costs are charged to the Trust only when cash has been paid for those expenses. In addition, the Royalty Interests are not burdened by field and lease operating expenses. Thus, the statement shows
distributable income, defined as income of the Trust available for distribution to the Trust unitholders before application of those unitholders' additional expenses, if any, for depreciation, depletion, and amortization, interest and income taxes. The revenues are reflected net of existing royalties and overriding royalties and have been reduced by gathering/post-production expenses.
Revenue and Expenses:
The Trust serves as a pass-through entity, with items of depletion, interest income and expense, and income tax attributes being based upon the status and election of the unitholders. Thus, the Statements of Distributable Income show Income available for distribution before application of those unitholders' additional expenses, if any, for depletion, interest income and expense, and income taxes.
The Trust uses the accrual basis to recognize revenue, with royalty income recorded as reserves are extracted from the Underlying Properties and sold. Expenses are recognized when paid.
Royalty Interest in Gas Properties:
The Royalty Interests in gas properties are assessed to determine whether the net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to Accounting Standards Codification 360, Property, Plant and Equipment ("ASC 360"). The Trust determines whether an impairment charge is necessary to its investment in the Royalty Interests in gas properties if total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. Determination as to whether and how much an asset is impaired involves estimates of highly uncertain matters such as future commodity prices, the effects of inflation, weighted average cost of capital, and technology improvements on post-production costs and the outlook for national or regional market supply and demand conditions. Estimates of undiscounted future net revenues attributable to proved gas reserves utilize NYMEX forward pricing curves. At December 31, 2017, 2016, and 2015, the undiscounted future net revenues exceeded the Net royalty interest in the gas properties, and therefore no impairment was necessary in any year presented. Significant dispositions or abandonment of the Underlying Properties, if necessary, are charged to Royalty Interests and the Trust Corpus.
Amortization of the Royalty Interests in gas properties is calculated on a units-of-production basis, whereby the Trust's cost basis in the properties is divided by Trust total proved reserves to derive an amortization rate per reserve unit. Such amortization does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.
The conveyance of the Royalty Interests to the Trust was accounted for as a purchase transaction. The $352,100,000 reflected in the Statements of Assets, Liabilities and Trust Corpus as Royalty Interests in Gas Properties represents 17,605,000 Trust Units valued at $20.00 per unit. The carrying value of the Trust's investment in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Hedge Contracts
The primary asset of and source of income to the Trust are the Royalty Interests, which generally entitle the Trust to receive varying portions of the net proceeds from natural gas production from the Underlying Properties. Consequently, the Trust is exposed to market risk from fluctuations in natural gas prices. Through March 31, 2014 the Royalty Interests were subject to the hedge contracts which were intended to reduce the Trust's exposure to natural gas price volatility. Since the expiration on March 31, 2014, of all hedge contracts held by the Trust, the Trust has had, and will continue to have, greater exposure to market risk from the fluctuation in natural gas prices.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Report of Independent Registered Public Accounting Firm
To the Unit Holders of ECA Marcellus Trust I and The Bank of New York Mellon Trust Company, N.A., as Trustee of ECA Marcellus Trust I
Opinion on the Financial Statements
We have audited the accompanying statements of assets, liabilities, and trust corpus of ECA Marcellus Trust I (the Trust) as of December 31, 2017 and 2016, and the related statements of distributable income and trust corpus for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Trust at December 31, 2017 and 2016, and the results of its distributable income and trust corpus for each of the three years in the period ended December 31, 2017, in conformity with the modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Trust's auditor since 2010.
Pittsburgh, Pennsylvania
March 20,
ECA Marcellus Trust I
Statements of Assets, Liabilities, and Trust Corpus
As of December 31,
See notes to the audited financial statements.
ECA Marcellus Trust I
Statements of Distributable Income
See notes to the audited financial statements.
ECA Marcellus Trust I
Statements of Trust Corpus
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 is a Delaware statutory trust formed in March 2010 by Energy Corporation of America ("Legacy ECA") to own royalty interests in fourteen producing horizontal natural gas wells producing from the Marcellus Shale formation, all of which are online and are located in Greene County, Pennsylvania (the "Producing Wells") and royalty interests in 52 horizontal natural gas development wells subsequently drilled to the Marcellus Shale formation (the "PUD Wells") within the "Area of Mutual Interest," or "AMI", comprising approximately 9,300 acres held by Legacy ECA, of which it owned substantially all of the working interests, in Greene County, Pennsylvania. The effective date of the Trust was April 1, 2010; consequently, the Trust received the proceeds of production attributable to the PDP Royalty Interest (defined herein) from that date even though the PDP Royalty Interest was not conveyed to the Trust until the closing of the initial public offering on July 7, 2010. The total number of units the Trust is authorized to issue is 17,605,000 units, all of which are now common units. The royalty interests were conveyed from Legacy ECA's working interest in the Producing Wells and the PUD Wells limited to the Marcellus Shale formation (the "Underlying Properties"). The royalty interest in the Producing Wells (the "PDP Royalty Interest") entitles the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to Legacy ECA's interest in the Producing Wells. The royalty interest in the PUD Wells (the "PUD Royalty Interest" and collectively with the PDP Royalty Interest, the "Royalty Interests") entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to Legacy ECA's interest in the PUD Wells. In November 2017, Greylock Energy, LLC, and certain of its wholly owned subsidiaries ("Greylock") acquired substantially of the assets of Legacy ECA, as described in Note 4.
The Trust's cash receipts in respect of the Royalty Interests are determined after deducting post-production costs and any applicable taxes associated with the PDP and PUD Royalty Interests. The Trust's cash available for distribution is reduced by Trust administrative expenses. Post-production costs generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Charges (the "Post-Production Services Fee") payable to Legacy ECA for such post-production costs on the Greene County Gathering System were limited to $0.52 per MMBtu gathered until Legacy ECA fulfilled its drilling obligation (which it did in November 2011); thereafter, Legacy ECA had the right and Greylock currently has the right to increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System. Additionally, if electric compression is utilized in lieu of gas as fuel in the compression process, the Trust will be charged for the electric usage as provided for in the Trust conveyance documents.
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting Trust administrative expenses, including the costs incurred as a result of being a publicly traded entity, on or about the 60th day following the completion of each quarter. Unless sooner liquidated, the Trust will liquidate on or about March 31, 2030 (the "Termination Date"). At the termination of the Trust, 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will revert automatically to Greylock. The remaining 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will be sold, and the net proceeds will be distributed pro rata to the unitholders soon after the termination of the Trust. Greylock will have a right of first refusal to purchase the remaining 50% of the Royalty Interests at the termination of the Trust.
ECA MARCELLUS TRUST I
NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)
NOTE 1. Organization of the Trust (Continued)
The business and affairs of the Trust are administered by The Bank of New York Mellon Trust Company, N.A. as Trustee. Although Greylock operates all of the Producing Wells and all of the PUD Wells, Greylock has no ability to manage or influence the management of the Trust. Neither the Trust nor the Trustee has any authority or responsibility for, or any involvement with or influence over, any aspect of the operations on or relating to the properties to which the Royalty Interests relate.
NOTE 2. Basis of Presentation
The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Without limiting the foregoing statement, the information furnished is based upon certain estimates of the revenues attributable to the Trust from natural gas production and is therefore subject to adjustment in future periods to reflect actual production for the periods presented.
NOTE 3. Significant Accounting Policies
The accompanying audited financial information has been prepared by the Trustee in accordance with the instructions to Form 10-K. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP") because certain cash reserves may be established for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. Amortization of expired floor price contract premiums does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Amortization of the investment in overriding royalty interests calculated on a unit-of-production basis is charged directly to Trust Corpus. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission ("SEC") as specified by FASB ASC Topic 932 Extractive Activities-Oil and Gas: Financial Statements of Royalty Trusts. Income determined on the basis of GAAP would include all expenses incurred for the period presented. However, the Trust serves as a pass-through entity, with expenses for depreciation, depletion, and amortization, interest and income taxes being based on the status and elections of the Trust unitholders. General and administrative expenses, production taxes or any other allowable costs are charged to the Trust only when cash has been paid for those expenses. In addition, the Royalty Interest is not burdened by field and lease operating expenses. Thus, the statement shows distributable income, defined as income of the Trust available for distribution to the Trust unitholders before application of those additional expenses, if any, for depreciation, depletion, and amortization, interest and income taxes. The revenues are presented net of existing royalties and overriding royalties and have been reduced by gathering/post-production expenses.
Cash:
Cash may include highly liquid instruments maturing in three months or less from the date acquired.
ECA MARCELLUS TRUST I
NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)
NOTE 3. Significant Accounting Policies (Continued)
Use of Estimates in the Preparation of Financial Statements:
The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue and Expenses:
The Trust serves as a pass-through entity, with items of depletion, interest income and expense, and income tax attributes being based upon the status and election of the unitholders. Thus, the Statements of Distributable Income show Income available for distribution before application of those unitholders' additional expenses, if any, for depletion, interest income and expense, and income taxes.
The Trust uses the accrual basis to recognize revenue, with royalty income recorded as reserves are extracted from the Underlying Properties and sold. Expenses are recognized when paid.
Royalty Interest in Gas Properties:
The Royalty Interests in gas properties are assessed to determine whether the net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to Accounting Standards Codification 360, Property, Plant and Equipment ("ASC 360"). The Trust determines whether an impairment charge is necessary to its investment in the Royalty Interests in gas properties if total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. Determination as to whether and how much an asset is impaired involves estimates of highly uncertain matters such as future commodity prices, the effects of inflation, weighted average cost of capital, and technology improvements on post-production costs and the outlook for national or regional market supply and demand conditions. Estimates of undiscounted future net revenues attributable to proved gas reserves utilize NYMEX forward pricing curves. At December 31, 2017, 2016, and 2015, the undiscounted future net revenues exceeded the Net royalty interest in the gas properties, and therefore no impairment was necessary in any year presented. Significant dispositions or abandonment of the Underlying Properties, if necessary, are charged to Royalty Interests and the Trust Corpus.
Amortization of the Royalty Interests in gas properties is calculated on a units-of-production basis, whereby the Trust's cost basis in the properties is divided by Trust total proved reserves to derive an amortization rate per reserve unit. Such amortization does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.
The conveyance of the Royalty Interests to the Trust was accounted for as a purchase transaction. The $352,100,000 reflected in the Statements of Assets, Liabilities and Trust Corpus as Royalty Interests in Gas Properties represents 17,605,000 Trust Units valued at $20.00 per unit. The carrying value of the Trust's investment in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.
ECA MARCELLUS TRUST I
NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)
NOTE 4. Reaffirmation Agreement
On November 29, 2017, Greylock acquired substantially all of the gas production and midstream assets of Legacy ECA, including Legacy ECA's interests in certain natural gas properties that are subject to royalty interests held by the Trust.
In connection with the transaction, Greylock assumed all of Legacy ECA's obligations under the Amended and Restated Trust Agreement among the Trust, Legacy ECA and the Trustee, and other instruments to which Legacy ECA and the Trustee are parties, including (1) the Administrative Services Agreement by and among Legacy ECA, the Trust and the Trustee dated July 7, 2010, and (2) a letter agreement between Legacy ECA and the Trustee regarding certain loans to be made by Legacy ECA to the Trust as necessary to enable the Trust to pay its liabilities as they become due (the "Letter Agreement"). In addition, Legacy ECA, Greylock, and the Trustee entered into a Reaffirmation and Amendment of Mortgage, Assignment of Leases, Security Agreement, Fixture Filing and Financing Statement (the "Reaffirmation Agreement"), pursuant to which, among other things, Greylock (1) reaffirmed the liens and the security interest granted pursuant to the existing mortgage securing the interests in the subject properties, as well as the mortgage and the obligations of Legacy ECA under the mortgage, and (2) assumed the obligations of Legacy ECA under the Letter Agreement.
NOTE 5. Income Taxes
The Trust is a Delaware statutory trust, which is taxed as a partnership for federal and state income taxes. Accordingly, no provision for federal or state income taxes has been made. Uncertain tax positions are accounted for under ASC 740, Income Taxes (ASC 740), which prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. Additionally, ASC 740 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The Trust has not identified any uncertain tax positions during the years ended December 31, 2017 or 2016.
NOTE 6. Related Party Transactions
Trustee Administrative Fee:
Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $150,000 to the Trustee. Although the Trust Agreement permitted this fee to be adjusted beginning on the fifth anniversary of the Trust, the fee remained unchanged for the year ended December 31, 2017. These costs, as well as those to be paid to Greylock pursuant to the Administrative Services Agreement referred to below, are deducted by the Trust in the period paid.
Administrative Services Fee:
The Trust and Greylock are parties to an Administrative Services Agreement that obligates the Trust to pay Greylock an administrative services fee for accounting, bookkeeping and informational services to be performed by Greylock on behalf of the Trust relating to the Royalty Interests. The annual fee of $60,000 is payable in equal quarterly installments. Under certain circumstances, Greylock and the Trustee each may terminate the Administrative Services Agreement at any time following delivery of notice no less than 90 days prior to the date of termination.
ECA MARCELLUS TRUST I
NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)
NOTE 6. Related Party Transactions (Continued)
Supplemental Reserve Information (Unaudited):
Information regarding estimates of the proved natural gas reserves attributable to the Trust is based on reports prepared by independent petroleum engineering consultants. Such estimates were prepared in accordance with guidelines established by the SEC. Accordingly, the estimates were based on existing economic and operating conditions. Numerous uncertainties are inherent in estimating reserve volumes and values and such estimates are subject to change as additional information becomes available.
The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.
The standardized measure of discounted future net cash flows was determined based on reserve estimates prepared by the independent petroleum engineering consultants, Ryder Scott Company, L.P.
The following table reconciles the estimated quantities of the proved natural gas reserves attributable to the Trust's interest from January 1, 2015 to December 31, 2017:
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
ECA MARCELLUS TRUST I
NOTES TO AUDITED FINANCIAL STATEMENTS (Continued)
NOTE 6. Related Party Transactions (Continued)
defined by contractual arrangements as required by the SEC regulations. The following is the standardized measure of discounted future net cash flows as of December 31 (in thousands):
(1)No provision for federal or state income taxes has been provided for in the calculation because taxable income is passed through to the unitholders of the Trust.
Changes in Standardized Measure of Discounted Future Net Cash Flows:
The following schedule reconciles the changes from January 1, 2015 to December 31, 2017 in the standardized measure of discounted future net cash flows relating to proved reserves (in thousands):
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and regulations promulgated by the SEC. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Greylock to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trustee's disclosure controls and procedures. Sarah Newell, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.
Due to the contractual arrangements of the Trust Agreement and the conveyances, the Trustee relies on (i) information provided by Greylock, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, and (ii) conclusions and reports regarding reserves by the Trust's independent reserve engineers. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 of this report, for a description of certain risks relating to these arrangements and reliance on information when reported by Greylock to the Trustee and recorded in the Trust's results of operations.
Trustee's Report on Internal Control over Financial Reporting
The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a- 15(f) promulgated under the Exchange Act. The Trustee conducted an evaluation of the effectiveness of the Trust's internal control over financial reporting based on the criteria established 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, 2017.
A registrant's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A registrant's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified basis of accounting discussed above, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrant's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject
to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Further, the design of disclosure controls and procedures and internal control over financial reporting must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.
Changes in Internal Control over Financial Reporting. During the quarter ended December 31, 2017, there has been no change in the Trustee's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee's internal control over financial reporting relating to the Trust. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Greylock.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
The Trust has no directors or executive officers. The Trustee is a corporate Trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust units at a meeting at which a quorum is present.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires officers, directors and the holders of more than 10 percent of the Trust units to file with the SEC reports regarding their ownership and changes in ownership of the Trust units. The Trust has no officers or directors. The Trustee is not aware of any 10 percent unitholder having failed to comply with Section 16(a) filing requirements in 2017.
Audit Committee and Nominating Committee
Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.
Code of Ethics
The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Trustee must comply with the Trustee's code of ethics.
Item 11.
Item 11. Executive Compensation.
During the years ended December 31, 2015, 2016 and 2017, the Trustee received administrative fees from the Trust pursuant to the Trust Agreement. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
(a)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 units as of March 16, 2018.
(b)Security Ownership of Management. Not applicable.
(c)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.
Item 13.
Item 13. Certain Relationships, Related Transactions and Director Independence.
Administrative Services Agreement
Under the terms of the Administrative Services Agreement, the Trust pays a quarterly administration fee of $15,000 to Greylock. General and administrative expenses in the Trust's statements of distributable income for the years ended December 31, 2017, 2016 and 2015 include
$60,000 in administrative fees for each year. Greylock and the Trustee each may terminate the provisions of the Administrative Services Agreement relating to the provision by Greylock of administrative services at any time following delivery of notice no less than 90 days prior to the date of termination; provided, however, that Greylock may not terminate the Administrative Services Agreement except in connection with Greylock's transfer of some or all of the Subject Interests, as defined in the Conveyances, and then only with respect to the services to be provided with respect to the Subject Interests being transferred, and only upon the delivery to the Trustee of an agreement of the transferee of such Subject interests reasonably satisfactory to the Trustee in which such transferee assumes the responsibility to perform the services relating to the Subject Interests being transferred.
Trustee Administrative Fee
Under the terms of the Trust Agreement, the Trust pays an annual administrative fee to the Trustee of $150,000, paid in four quarterly installments of $37,500. The Trust also pays an annual administrative fee to the Delaware Trustee of $2,500. General and administrative expenses in the Trust's statements of distributable income for the twelve months ended December 31, 2017, 2016 and 2015 included administrative fees of approximately $165,000, $114,000, and $150,000, respectively. Any variances from the annual fee are the result of such fees being recorded by the Trust in the period paid rather than in the period incurred.
Director Independence
The Trust does not have a board of directors.
Item 14.
Item 14. Principal Accounting Fees and Services.
The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee. The Trustee has appointed Ernst & Young LLP as the independent registered public accounting firm to audit the Trust's financial statements for the fiscal year ending December 31, 2018. During fiscal 2017 and 2016, Ernst & Young LLP served as the Trust's independent registered public accounting firm.
The following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2017 and 2016 by Ernst & Young LLP:
(1)Fees for audit services included fees for the reviews of the Trust's quarterly financial statements.
PART IV
Item 15.
Item 15. Exhibits 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:
Reports of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2017 and 2016
Statements of Distributable Income for the Years Ended December 31, 2017, 2016 and 2015
Statements of Trust Corpus as of December 31, 2017, 2016 and 2015
Notes to Financial Statements
Supplemental Reserve Information (Unaudited)
(a)(2) Schedules
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.
*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 20,
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.
Appendix A
January 18,
ECA Marcellus Trust I
The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue, Suite 500
Austin, Texas 78701
Gentlemen:
At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain royalty interests of ECA Marcellus Trust I (the Trust) as of December 31, 2017. The Trust was originally formed by Energy Corporation of America (ECA) to own royalty interests in natural gas properties now owned and operated by Greylock Energy (Greylock) in the Marcellus Shale formation in Greene County, Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 18, 2018 and presented herein, was prepared for public disclosure by the Trust in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The properties evaluated by Ryder Scott represent 100 percent of the total net proved reserves of the Trust as of December 31, 2017.
The estimated reserves and future net income amounts presented in this report, as of December 31, 2017, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Royalty Interests of
ECA Marcellus Trust I
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All gas volumes are reported on an "as sold basis" expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of 60 degrees Fahrenheit and 14.73 psia.
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants. The program was used at the request of the Trust. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
The future gross revenue is normally presented after the deduction of production taxes, but in the State of Pennsylvania, these are zero. Furthermore, the Trust owns only a royalty interest, and the deductions shown as "Other" deductions in the cash flows incorporate the Trust's share of post-production costs including gathering, compression, and transportation fees. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Gas reserves account for 100 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.
The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "Petroleum Reserves Definitions" is included as an attachment to this report. The various proved reserve status categories are defined under the attachment entitled "Petroleum Reserves Status Definitions and Guidelines" in this report.
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
Reserves are "estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations." All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of
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these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At the Trust's request, this report addresses only the proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are "those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward." The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a "high degree of confidence that the quantities will be recovered."
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that "as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease." Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts. Certain contractual obligations of Greylock to produce these volumes have been incorporated into this evaluation.
Greylock's operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which the Trust owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.
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In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are much more likely than not to be achieved." The SEC states that "probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
All of the proved reserves for the properties included herein were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through mid-December 2017. The data utilized in this analysis were furnished to Ryder Scott by Greylock and were considered sufficient for the purpose thereof.
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Greylock has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Greylock with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, the Pennsylvania impact fee, other costs such as gathering and/or transportation fees, product prices based on the SEC regulations, adjustments or differentials to product prices, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Greylock. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
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In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the "SEC Regulations." In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
Our forecasts of future production rates for the producing properties included herein are based on historical performance data and the established decline trend of each well. Future production rates may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.
Greylock furnished us with the above mentioned average prices in effect on December 31, 2017. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the "benchmark price" and "price reference" used for the geographic area included in the report.
The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as "differentials." The differentials used in the preparation of this report were furnished to us by Greylock. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Greylock to determine these differentials.
In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the "average realized price." The average realized price shown in the table below was determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.
The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.
A-5
Costs
Operating costs for the leases and wells in this report were furnished by Greylock. They are based on the operating expense reports of Greylock and include only those costs directly applicable to the leases or wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. Post-production costs, including gathering, compression, and transportation fees, are shown as "Other" deductions. The costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Greylock. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells. All costs were held constant throughout the life of the properties. It should be noted that the Trust only owns a royalty interest in the subject wells and is only burdened by its share of the previously mentioned post-production costs. The operating expenses supplied by Greylock were used only to determine the economic life of each property.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to the Trust or Greylock. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by the Trust.
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The Trust makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, the Trust has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statement on Form S-3 of the Trust of the references to our name as well as to the references to our third party report for the Trust, which appears in the December 31, 2017 annual report on Form 10-K of the Trust. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by the Trust.
We have provided the Trust with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by the Trust and the original signed report letter, the original signed report letter shall control and supersede the digital version.
The data and work products used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No.
\s\ Stephen E. Gardner, P.E.
Stephen E. Gardner, P.E.
Colorado License No. 44720
Senior Vice President
SEG (DCR)/pl
[Seal]
A-7
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.
Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner's geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.
Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, currently serving in the latter organization's Denver Chapter as Chairman.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2017 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference in Houston, Texas which covered a variety of topics including well analysis and type well construction techniques, unconventional resource issues, SEC comment letter trends, and others. At the same conference, Mr. Gardner was featured as a speaker, presenting analysis of the SCOOP/STACK plays in Oklahoma. In addition, Mr. Gardner attended various SPEE technical seminars and internal company training during 2017 covering topics such as analysis software, statistical methods, advanced decline analysis techniques, ethics, reserves evaluation, waterflooding, and more.
Based on his educational background, professional training and more than 12 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007.
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