ITEM 1. BUSINESS DESCRIPTION OF THE TRUST
The Eastern American Natural Gas Trust (the "Trust") was formed under the Delaware Business Trust Act pursuant to a Trust Agreement (the "Trust Agreement") among Eastern American Energy Corporation ("Eastern American"), as grantor, Bank of Montreal Trust Company, as Trustee ("Trustee"), and Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee"). The Trust was formed to acquire and hold net profits interests (the "Net Profits Interests") created from the working interests owned by Eastern American in 650 producing gas wells and 65 proved development well locations located in West Virginia and Pennsylvania (the "Underlying Properties"). A portion of the production from the wells burdened by the Net Profits Interests is eligible for credits ("Section 29 Credits") under the Internal Revenue Code of 1986 for production of gas from Devonian shale or tight sand formations. The Net Profits Interests consist of a royalty interest in 322 wells and a term interest in the remaining wells and locations. Eastern American is obligated to drill and complete, at its expense, 65 development wells (the "Development Wells") on the development well locations conveyed to the Trust. As of December 31, 1996, Eastern American had drilled 56 development wells. Eastern American is required to drill 3 additional development wells by March 31, 1997 and 6 more during the remainder of 1997. After May 15, 2012 and prior to or on May 15, 2013 (the "Liquidation Date"), the Trustee is required to sell the royalty interests and liquidate the Trust.
On March 15, 1993, 5,900,000 Depositary Units were issued in a public offering at an initial public offering price of $20.50 per Depositary Unit. Each Depositary Unit consists of beneficial ownership of one unit of beneficial interest ("Trust Unit") in the Trust and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon United States Treasury obligation ("Treasury Obligation") maturing on May 15, 2013. Of the net proceeds from such offering, $27,787,820 was used to purchase $118,000,000 in face amount of Treasury Obligations and $93,162,180 was retained by Eastern American in consideration for the conveyance of the Net Profits Interests to the Trust. The Trust acquired the Net Profits Interests effective as of January 1, 1993.
The Net Profits Interests are passive in nature, and neither the Trustee nor the Delaware Trustee has management control or authority over, nor any responsibility relating to, the operation of the properties subject to the Net Profits Interests. The Trust Agreement provides, among other things, that: the Trust shall not engage in any business or commercial activity or acquire any asset other than the Net Profits Interests initially conveyed to the Trust; the Trustee may establish a reserve for payment of any liability which is contingent, uncertain in amount or that is not currently due and payable; the Trustee is authorized to borrow funds required to pay liabilities of the Trust, provided that such borrowings are repaid in full prior to further distributions to holders of Depositary Units ("Unitholders") and the Trustee will make quarterly cash distributions to Unitholders from funds of the Trust. The discussion of terms of the Trust Agreement contained herein is qualified in its entirety by reference to the Trust Agreement itself, which is incorporated by reference as an exhibit to this Form 10-K and is available upon request from the Trustee.
The Trustee is paid an annual fee of approximately $45,000. The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees, printing costs and other administrative expenses incurred by or at the direction of the Trustee. The total of all Trustee fees and Trust administrative expenses for 1996 was $208,787 and is anticipated to aggregate between $200,000 and $250,000 per year, although such costs could be materially higher or lower, depending primarily on the amounts of expenses the Trust incurs for professional services, particularly legal, accounting and engineering services. In addition to such expenses, in 1996, the Trust paid Eastern American an overhead reimbursement of $232,832 which will increase by 3.5% per year, payable quarterly.
The following descriptions of the Net Profits Interests, and the calculation of amounts payable to the Trust in respect thereof, are subject to and qualified by the more detailed provisions of the Conveyances, as defined below, incorporated by reference as exhibits to this Form 10-K and available upon request from the Trustee. The information contained herein relating to the operations of the Underlying Properties, as well as information upon which the reserve figures and financial information contained herein were derived, was furnished to the Trustee by Eastern American.
THE NET PROFITS INTERESTS
THE CONVEYANCES
The Net Profits Interests were conveyed to the Trust pursuant to two conveyances - one conveying the Royalty NPI (the "Royalty NPI Conveyance") and the other conveying the Term NPI (the "Term NPI Conveyance," and together with the Royalty NPI Conveyance, the "Conveyances"). In limited circumstances, Eastern American may transfer the Underlying Properties and require the Trust to release the Net Profits Interests, subject to payment to the Trust of the fair value of the interests released. See " Sale and Abandonment of Underlying Properties; Sale of Royalty NPI."
The Underlying Properties are subject to and burdened by the Net Profits Interests. The interests of Eastern American comprising the Underlying Properties represent, on average, a working interest of approximately 90% and a net revenue interest of approximately 76%. The Conveyances provide that the Trust is only entitled to gas produced from the specific wells identified in the Conveyances and is not entitled to any gas produced from adjacent wells (including adjacent wells subject to the same lease or farmout agreement as the wells subject to the Net Profits Interests). Gas produced from the Underlying Properties which is attributable to the Net Profits Interests is purchased from the Trust by Eastern Marketing Corporation, a wholly-owned subsidiary of Eastern American ("Eastern Marketing") pursuant to a gas purchase contract (the "Gas Purchase Contract"). The volumes attributable to the Net Profits Interests and the purchase price for such gas is calculated for each calendar quarter, and payment for such gas is made to the Trust not later than the 10th day of the third calendar month following the end of each calendar quarter.
The Royalty NPI is not limited in term. Under the Trust Agreement, the Trustee is directed to sell the Royalty NPI after May 15, 2012 and prior to May 15, 2013, and net proceeds from such sale will be distributed to Unitholders on the first quarterly payment date following the receipt of such proceeds by the Trust. The Term NPI will expire on the earlier of May 15, 2013 or such time as 41,683 MMCF of gas has been produced which is attributable to Eastern American's net revenue interests in the properties burdened by the Term NPI. As of December 31, 1996, 8.621 MMcf of such gas had been produced.
The definitions, formulas, accounting procedures and other terms governing the computation of Net Proceeds are detailed and extensive, and reference is made to both the Royalty NPI Conveyance and the Term NPI Conveyance for a more detailed discussion of the computation thereof. Forms of the Conveyances have been incorporated by reference as exhibits to this report.
Eastern American may sell the Underlying Properties, subject to and burdened by the Net Profits Interests, without the consent of the Trust or the Unitholders. Eastern American may also require the Trust to release Net Profits Interests from the Trust's ownership thereof, without the consent of the Trust or the Unitholders, under certain circumstances. In addition, any abandonment of a well included in the Underlying Properties or the Development Wells will extinguish that portion of the Net Profits Interests that relate to such well.
CALCULATION OF NET PROCEEDS
The Conveyances and the Gas Purchase Contract entitle the Trust to receive an amount of cash for each calendar quarter equal to the Net Proceeds for such quarter. "Net Proceeds" for any calendar quarter generally means an amount of cash equal to (a) 90% of a volume of gas equal to (i) the volume of gas produced during such quarter attributable to the Underlying Properties less (ii) a volume of gas equal to Chargeable Costs, as defined below, for such quarter, multiplied by (b) the applicable price for such quarter under the Gas Purchase Contract. If, for any reason, the Gas Purchase Contract terminates prior to the Liquidation Date, "Net Proceeds" will mean an amount of cash equal to (a) 90% of a volume of gas equal to (i) the volume of gas produced during such quarter attributable to the Underlying Properties less (ii) a volume of gas equal to Chargeable Costs for such quarter, multiplied by (b) the applicable price for such quarter determined in accordance with the Conveyances. Pursuant to the Conveyances, the Trust will not be entitled to receive any natural gas liquids produced from the Underlying Properties or any proceeds relating thereto.
"Chargeable Costs" is that volume of gas which equates in value, determined by reference to the relevant sales price under the Gas Purchase Contract or the Conveyances, as applicable, to the sum of the Operating Cost Charge, Capital Costs and Taxes. The "Operating Cost Charge" for 1994 was $419,131, for 1995 was $437,068 and for 1996 was $449,896. In 1997 and subsequent years the Operating Cost Charge will escalate, based on increases in the index of average weekly earnings of Crude Petroleum and Gas Production Workers (published by the United States Department of Labor, Bureau of Labor Statistics), but not more than 5% per year. The Operating Cost Charge will not be increased as Development Wells are completed but will be reduced for each well that is sold (free of the Net Profits Interests) or plugged and abandoned. "Capital Costs" means Eastern American's working interest share of capital costs for operations on the Underlying Properties, but only for items having a useful life of at least three years, and not including any capital costs incurred in drilling the Development Wells. "Taxes" means ad valorem taxes, production and severance taxes, and other taxes imposed on Eastern American's or the Trust's interests in the Underlying Properties, or production therefrom.
Although the Trust indirectly bears a share of Chargeable Costs in the calculation of Net Proceeds, the Trust is not directly liable for any share of the costs, risks, and liabilities associated with the ownership or operation of the Underlying Properties. If the Trust ever receives payments in excess of the Net Proceeds or other amounts it was not entitled to receive, the Trust will not be required to refund the money, but Eastern American may recover the amount of such overpayments in accordance with the Conveyances.
The Conveyances require Eastern American to maintain books, records, and accounts sufficient to calculate the volumes of gas and the share of Net Proceeds payable to the Trust. Eastern American provides to the Trust quarterly and annual statements of applicable production, revenues, and costs necessary for the Trust to prepare quarterly and annual financial statements with respect to the Net Profits Interests and the Underlying Properties. The financial statements of the Trust are audited annually at the Trust's expense.
GAS PURCHASE CONTRACT
Gas production attributable to the Net Profits Interests is purchased from the Trust by Eastern Marketing, a wholly owned subsidiary of Eastern American, pursuant to the Gas Purchase Contract which effectively commenced as of January 1, 1993 and expires upon the termination of the Trust.
Pursuant to the Gas Purchase Contract, Eastern Marketing is obligated to purchase such gas production at a purchase price per Mcf equal to the greater of the Index Price, as defined below, and the Floor Price, as defined below, for gas produced during each quarter of the initial seven years of the Trust ending January 1, 2000 (the "Primary Term"), and at a purchase price per Mcf equal to the Index Price for gas produced in any quarter after the Primary Term. The Floor Price, which varies for each calendar year during the Primary Term, is a price per Mcf which is expected to provide Unitholders a minimum distribution of $1.80 per Depositary Unit on an annualized basis during the Primary Term assuming such price was received by the Trust for all gas attributable to the Net Profits Interests produced for such year, assuming that actual gas production is not less than that estimated in the initial Reserve Report filed with the Securities and Exchange Commission, and assuming that certain costs are not more than estimated. The following table sets forth the Floor Prices for each of the years during the Primary Term.
FLOOR PRICE IMPLIED HENRY HUB AVERAGE YEAR (PER MCF) SPOT PRICE (PER MMBTU) (1) - ---- ----------- -------------------------- 1993 ...................... $2.16 $0.76 1994 ...................... $2.31 $0.91 1995 ...................... $2.35 $0.80 1996 ...................... $2.36 $0.54 1997 ...................... $2.57 $0.84 1998 ...................... $2.84 $1.28 1999 ...................... $3.09 $1.65
(1) Represents the Henry Hub Average Spot Price portion of the Variable Price component used in calculating the Floor Price.
The Index Price for any quarter is a weighted average price determined by reference to the Fixed Price component, which will be given a 66 2/3% weighing during the Primary Term and none thereafter, and a Variable Price component, which will be given a 33 1/3% weighing during the Primary Term and 100% thereafter. The Fixed Price was equal to $2.79 per Mcf for the 1994 calendar year, $2.93 for 1995, $3.08 for 1996 and escalates 5% for each year thereafter during the Primary Term. The Variable Price for any quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter equal to the price obtained with respect to each of the three months in such quarter, in the manner specified below, and then taking the average of the prices determined for each of such three months. The price determined for any month of such quarter is equal to the average of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in THE WALL STREET JOURNAL, for such contracts which expired in each of the five months prior to such month, (ii) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported in THE WALL STREET JOURNAL, for such contracts which expire during such month and (iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures Contracts determined as of the contract settlement date for such month, as reported in THE WALL STREET JOURNAL, for such contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to be delivered to the Henry Hub which is traded on the New York Mercantile Exchange. After the Primary Term, the applicable purchase price under the Gas Purchase Contract will be the Index Price, determined solely by reference to the Variable Price component.
In the event that a federal excise tax or other form of federal tax on natural gas production is adopted after the effective date of
the Conveyances which has the effect of increasing Chargeable Costs under the Conveyances from the level otherwise applicable for any calendar quarter during the Primary Term, the volume of gas to which the Trust is entitled to receive under the Conveyances will be less than it would otherwise be entitled if not for such tax. To offset the effect of a reduced volume of gas attributable to such a tax, the Gas Purchase Contract provides, in effect, that the amount payable for any quarter during the Primary Term will not be less than the net payment which would otherwise be received with respect to the Net Profits Interests if (i) Chargeable Costs for such quarter had not increased as a result of such tax and (ii) all gas attributable to the Trust for such quarter had been purchased at the Floor Price applicable for such quarter. In addition, if such a tax is imposed, the Fixed Price component of the Index Price will be increased if and to the extent that Eastern American receives higher gas prices for gas sold by Eastern American under the gas sales contract, dated March 27, 1991, between Eastern American and Seneca Power Partners, L.P. (the "Seneca Contract") than Eastern American would otherwise receive under such contract if not for the imposition of any such tax. The Seneca Contract does not provide any mechanism for price redetermination based on higher taxes and, therefore, there can be no assurance that any such price redetermination would occur if such a tax were adopted.
The purchase price paid to the Trust pursuant to the Gas Purchase Contract is a wellhead price and title to the gas purchased pursuant to the Gas Purchase Contract passes to Eastern Marketing at the point of delivery. Payments to the Trust for gas purchased pursuant to the Gas Purchase Contract are made by Eastern Marketing on or before the tenth day of the third calendar month following the end of each calendar quarter.
The Trust Agreement provides that the Trustee may not agree to any amendment to the Gas Purchase Contract which would materially and adversely affect the revenues to the Trust without the approval of the holders of a majority of the outstanding Trust Units. The Trust Agreement also provides that the Gas Purchase Contract may not be terminated by the Trust without the approval of the holders of a majority of the outstanding Trust Units. The Gas Purchase Contract and the Trust Agreement have been filed as exhibits to this Form 10-K. The foregoing summary of the principal provisions of the Gas Purchase Contract, and certain provisions of the Trust Agreement, is qualified in its entirety by reference to the terms of such agreements as set forth in such exhibits.
Eastern Marketing's rights and obligations under the Gas Purchase Contract are assignable under circumstances where the assignee unconditionally assumes Eastern Marketing's obligations under the Gas Purchase Contract, and then, only if such assignee (or assignee's parent corporation if such parent guarantees the assignee's obligations) has a rating assigned to its unsecured long-term debt by Moody's Investor Service of at least Baa+ and by Standard & Poor's Corporation of at least BBB-. Under such circumstances, Eastern Marketing and Eastern American would be released from their obligations under the Gas Purchase Contract. The Letter of Credit (defined below) however, would not be affected by any such assignment.
PERFORMANCE SUPPORT FOR GAS PURCHASE CONTRACT
Under a standby performance agreement, Eastern American has agreed to make payments under the Gas Purchase Contract to the extent such payments are not made by Eastern Marketing. In addition, performance by Eastern Marketing of its obligation to make payments required pursuant to the Gas Purchase Contract will be secured by a standby letter of credit (the "Letter of Credit"). The Letter of Credit has been issued by One Valley Bank N.A. (the "Letter of Credit Bank"). The Letter of Credit has a one-year term which will be renewed annually during the Primary Term, subject to the right of the Letter of Credit Bank not to renew upon giving written notice at least 30 days prior to the expiration of an annual term. The Letter of Credit was originally in the face amount of $15 million, and declined to $12 million on June 30, 1996 and will decline annually thereafter to an amount equal to the lesser of (i) the remaining undrawn face amount thereof as of such date and (ii) $9 million in 1997, $6 million in 1998 and $3 million in 1999. In the event of a failure by Eastern Marketing to make any required payment under the Gas Purchase Contract and a failure by Eastern American to make any such payment to the extent not made by Eastern Marketing, the Delaware Trustee shall draw on the Letter of Credit in the amount of such defaulted payment, up to the amount then remaining under the Letter of Credit.
Pursuant to the Trust Agreement, the Delaware Trustee is instructed to draw under the Letter of Credit in the event that (i) the Letter of Credit Bank notifies the Delaware Trustee, pursuant to the terms of the Letter of Credit, that the Letter of Credit will be terminated by the Letter of Credit Bank following the occurrence of an event of default as defined in the Agreement dated as of June 28, 1996 among Eastern American, Eastern Marketing and the Letter of Credit Bank (ii) the Letter of Credit Bank notifies the Delaware Trustee, pursuant to the terms of the Letter of Credit, that the Letter of Credit will not be renewed on any annual renewal date or (iii) the Gas Purchase Contract is terminated for any reason prior to its expiration date, including any such termination in connection with a bankruptcy or insolvency proceeding of Eastern Marketing. The amount of any such draw will be equal to the then remaining undrawn amount of the Letter of Credit; provided that, in the event that such payment exceeds the Production Payment Reserve Value (as defined), determined as of the date of such draw, the amount of such draw will be limited to an amount equal to the Production Payment Reserve Value. The Production Payment Reserve Value, as of the date of such draw, is defined generally as the discounted present value of the gas reserves which, based on estimated production levels and the payment schedule for the Production Payment Interest (as defined below), are expected to be available to make such payments. The proceeds received by the Delaware Trustee from any such draw will be distributed to Unitholders within 90 days following receipt thereof by the Delaware Trustee.
In the event of a draw under the Letter of Credit with respect to any of the circumstances described in the preceding paragraph, the Trust will be obligated to convey to Eastern Marketing a production payment interest ("Production Payment Interest") in the reserves attributable to the Net Profits Interests. The Production Payment Interest would obligate the Trust to make quarterly payments to Eastern Marketing from the production attributable to the Net Profits Interests. The amount of such payments would, in the aggregate, equal (i) the amount of any such draw on the Letter of Credit (the "Production Payment Amount"), subject to the offset as described below, plus (ii) an additional amount accruing on the unpaid portion of the Production Payment Amount at a rate equal to the lesser of 10% per annum and the prime rate of the Letter of Credit Bank plus 1%. The Production Payment Amount will be subject to reduction as an offset for any damages suffered by the Trust from any breach of the Gas Purchase Contract by Eastern Marketing (including damages for breach based on the termination thereof in connection with a bankruptcy or insolvency proceeding of Eastern Marketing).
Eastern American may at its election replace the Letter of Credit and the Letter of Credit Bank provided the replacement bank has at least $1.0 billion in assets, its senior unsecured debt at the time of such replacement is assigned a rating by Standard & Poor's Corporation of not less than BBB + and by Moody's Investor Service of not less than Baa2, and the letter of credit to be issued by such replacement bank is substantially identical to the Letter of Credit.
Prior to June 30, 1996 the Letter of Credit Bank was the Bank of Nova Scotia. Eastern American elected to replace the Bank of Nova Scotia with One Valley Bank N.A.
DISTRIBUTIONS AND INCOME COMPUTATIONS
The Trustee determines for each quarter the amount of cash available for distribution to holders of Depositary Units and the Trust Units evidenced thereby. Such amount (the "Quarterly Distribution Amount") is equal to the excess, if any, of the cash received by the Trust, on or before the 10th day of the third month following the end of each calendar quarter ending prior to the dissolution of the Trust, from the Net Profits Interests then held by the Trust attributable to production during such quarter, plus, with certain exceptions, any other cash receipts of the Trust during such quarter, over the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. Quarterly Distribution Amounts for each of the quarters in 1994 were $0.46, $0.48, $0.44 and $0.44, respectively, and for each of the quarters in 1995 were $0.39, $0.39, $0.38 and $0.43 respectively and for each of the quarters in 1996 were $0.39, $0.46, $0.45 and $0.46 respectively. Based on the payment procedures relating to the Net Profits Interests, cash received by the Trustee in a particular quarter from the Net Profits Interests reflects actual gas production for a portion of such quarter and a production estimate for the remainder of such quarter, such estimate to be adjusted to actual production in the following quarter. The Quarterly Distribution Amount for each quarter is payable to Unitholders of record on the last day of the second month following the end of such calendar quarter or such later date as the Trustee determines is required to comply with legal or stock exchange requirements ("Quarterly Record Date"). It is expected that the Trustee will continue to be able to distribute cash on or before the 15th day (or the next succeeding business day following such day if such day is not a business day) of the third month following the end of each calendar quarter to each person who was a Unitholder of record on the Quarterly Record Date, together with interest earned on such Quarterly Distribution Amount from the date of receipt thereof by the Trustee to the payment date.
The net taxable income of the Trust for each calendar quarter is reported by the Trustee for tax purposes as belonging to the holders of record to whom the Quarterly Distribution Amount was or will be distributed. Assuming that the Trust will be classified for tax purposes as a "grantor trust," the net taxable income will be realized by the holders for tax purposes in the calendar quarter received by the Trustee, rather than in the quarter distributed by the Trustee. Taxable income of a holder will differ from the Quarterly Distribution Amount because the Treasury Obligations will be treated as generating interest income for tax purposes. There may also be minor variances because of the possibility that, for example, a reserve will be established in one quarter that will not give rise to a tax deduction until a subsequent quarter, an expenditure paid for in one quarter will have to be amortized for tax purposes over several quarters, etc. See "Federal Income Tax Consequences."
Each holder of Depositary Units (including the underlying Trust Units) of record as of the record date for the final quarter of the Trust's existence will be entitled to receive a liquidating distribution equal to a pro rata portion of the net proceeds from the sale of the Royalty NPI (to the extent not previously distributed) and a pro rata portion of the proceeds from the matured Treasury Obligations.
SALE AND ABANDONMENT OF UNDERLYING PROPERTIES; SALE OF ROYALTY NPI
Eastern American and any transferees will have the right to abandon any well or working interest included in 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 Eastern American and the Trust in determining whether a well is capable of producing in paying quantities, Eastern American will be required under the Conveyances to make any such determination as would a reasonably prudent operator in the Appalachian Basin if it were acting with respect to its own properties, disregarding (i) the existence of the Net Profits Interests as a burden on such property and (ii) the direct or indirect effect, financial or otherwise, on Eastern American or any of its affiliates that may result from the performance by Eastern Marketing of its obligations under the Gas Purchase Contract.
Eastern American has the right, pursuant to the Conveyances, to sell all or any portion of the Underlying Properties without restrictions; however, the purchaser of any of the Underlying Properties will acquire such Underlying Properties subject to the Net Profits Interests relating thereto (except in certain circumstances described below where the Trust may be required to release the Net Profits Interests, subject to its receipt of the fair value thereof). Any such purchaser will be subject to the same standards of conduct with respect to development, operation and abandonment of such Underlying Properties as set forth in the preceding paragraph. Notwithstanding any such sale, Eastern American will remain obligated, pursuant to the terms of the Conveyances, to drill all of the Development Wells in accordance with the provisions of the Conveyances.
Eastern American may sell the Underlying Properties, subject to and burdened by the Net Profits Interests, without the consent of the Trust or the Unitholders. In addition, prior to January 1, 2003, Eastern American may, without the consent of the Trust or the Unitholders, require the Trust to release Net Profits Interests associated with any well which accounts for 0.25% or less of the total production from the Underlying Properties in the prior 12 months, provided that such releases cannot exceed five wells during any 12-month period. In addition, until January 1, 2010, such releases cannot exceed an aggregate value to the Trust of $500,000 during any 12-month period. Sales subsequent to that time may be made without regard to dollar limitations. These releases will be made only in connection with a sale by Eastern American of the Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such Net Profits Interests (taking into account the existence of the Gas Purchase Contract with respect to the gas attributable to the Net Profits Interests to be released). Any proceeds paid to the Trust are distributable to Unitholders for the quarter in which they are received.
The Trustee is required to sell all of the Royalty NPI after May 15, 2012 and prior to the Liquidation Date. The proceeds of such sale, together with the matured face amount of the Treasury Obligations, will be distributed to Unitholders on or prior to the Liquidation Date. Under the Trust Agreement, Eastern American has a right of first refusal to purchase any of the Royalty NPI at the fair value to the Trust, or if applicable the offered third-party price, prior to the Liquidation Date.
THE UNDERLYING PROPERTIES
GENERAL
The Underlying Properties are comprised of Eastern American's working interests in certain properties located in the Appalachian Basin states of West Virginia and Pennsylvania. As of December 31, 1996, such properties consisted of 692 producing gas wells and 9 proved development locations. The working interests of Eastern American comprising the Underlying Properties are held under leases and farmout agreements with third parties. Such working interests are subject to landowner's royalties (typically 12- 1/2%) and may be subject to additional royalties or other obligations burdening the working interests. Such royalties do not bear lease operating expenses, but reduce the revenue interests attributable to the Underlying Properties. Eastern American's interests comprising the Underlying Properties represent, on average, a working interest of approximately 90% and a net revenue interest of approximately 76%. As of December 31, 1996, proved developed and proved undeveloped reserves attributable to the Net Profits Interests (reflecting quantities of gas free of future costs and expenses based on estimated prices) were approximately 42,193 MMcf and 1.183 MMcf respectively (See " Reserves").
The Appalachian Basin is a mature producing region with well known geologic characteristics. Substantially all of the wells comprising of the Underlying Properties are relatively shallow, ranging from 2,500 to 5,500 feet, and many are completed to multiple producing zones. In general, the wells to which the Underlying Properties relate are proved producing properties with stable production profiles and generally long-lived production, often with total projected economic lives in excess of 25 years. Once drilled and completed, ongoing operating and maintenance requirements are low and only minimal, if any, capital expenditures are typically required.
The Underlying Properties initially included 65 specified development well locations for the drilling of the Development Wells by Eastern American. As of December 31, 1996, Eastern American had drilled 56 of the Development Wells. Eastern American is required to drill 3 additional Developmental Wells by March 31, 1997 and 6 more during the remainder of 1997. Eastern American is obligated to bear the costs of drilling and completing the Development Wells. Eastern American is required, pursuant to the applicable Conveyances, to complete and equip each Development Well that reasonably appears to Eastern American to be capable of producing gas in quantities sufficient to pay completion, equipping and operating costs. In making such decisions, Eastern American is required under the applicable Conveyance to act as a reasonably prudent operator would act in the Appalachian Basin under the same or similar circumstances if it were acting with respect to its own properties, disregarding (i) the existence of the Net Profits Interests as a burden on such property and (ii) the direct or indirect effect, financial or otherwise, on Eastern American or any of its affiliates that may result from the performance by Eastern Marketing of its obligations under the Gas Purchase Contract. Eastern American's obligation to drill any Development Well will be considered satisfied if the state of title to the drill site for such Development Well renders the well undrillable in Eastern American's good faith opinion under the reasonably prudent operator standard described above or if, after Eastern American has commenced drilling any such Development Well, it fails to reach total depth due to geological subsurface conditions or impenetrable substances. Although Eastern American has not obtained title opinions with respect to the drill sites for the Development Wells, Eastern American is not aware of any title deficiencies that would preclude it from drilling any of such wells. The Development Wells to be drilled are expected to have the same general production characteristics as the other wells included in the Underlying Properties. No assurances can be given, however, that any Development Well will produce in commercial quantities or as to the precise characteristics of any of these wells. Pursuant to the terms of the applicable Conveyance, Eastern American will remain obligated to drill all of the Development Wells regardless of whether the Underlying Profits Interests are sold by Eastern American or the Trust.
Eastern American acquired its interests in the Underlying Properties under or through (i) oil and gas leases granted by the mineral owner directly to Eastern American, (ii) assignments of oil and gas leases by the lessee who originally obtained the leases from the mineral owner, (iii) farmout agreements that grant Eastern American the right to earn interests in the properties covered by such agreements by drilling wells and (iv) the acquisitions of oil and gas interests by Eastern American.
Production from the wells to which the Underlying Properties relate is typically subject to, in one degree or another, (i) landowner royalties and other burdens and obligations retained under oil and gas leases, (ii) overriding royalty interests and (iii) interests of other working interest owners in the wells. The royalty and overriding interests entitle the holders thereof to a certain percentage of the oil and gas produced from the wells or the proceeds therefrom and are generally delivered free of all expenses of production but may be subject to post-production costs, such as production or gathering taxes, costs to treat the gas to render it marketable, and certain transportation or gathering costs. Royalty interests are usually reserved by the lessor under an oil and gas lease. Overriding royalty interests are carved out of a lessee's share of production under an oil and gas lease and are generally reserved by a predecessor in title or reserved under farmout agreements.
A farmout agreement is typically an agreement under which a lessee under an oil and gas lease (the "Farmor") agrees to grant to another party the right to drill wells on the tract covered by such lease and to earn certain acreage for drilling such wells. In the Appalachian Basin, the Farmor generally receives a well location fee and reserves an overriding royalty interest in the wells which typically ranges from 3.25% to 6.25%. Farmout agreements typically provide that wells must be drilled and completed as a condition to a transfer by the Farmor of the interest in the underlying lease.
RESERVES
PROVED RESERVES OF UNDERLYING PROPERTIES AND NET PROFITS INTERESTS. The following table sets forth, as of December 31, 1996, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties, the Royalty NPI and the Term NPI, in each case derived from a report of oil and gas reserves attributable to the Trust as of December 31, 1996 prepared by Ryder Scott Company (the "Reserve Report"). Proved reserve quantities attributable to the Net Profits Interests are calculated by subtracting an amount of gas sufficient, if sold at the prices used in preparing the reserve estimates, to pay the future estimated costs and expenses deducted in the calculation of Net Proceeds. Accordingly, the reserves attributable to the Net Profits Interests reflect quantities of gas that are free of future costs or expenses if the price and cost assumptions set forth in the Reserve Report occur. A decrease in the price assumption, or an increase in the cost assumption used in the Reserve Report would reduce the estimates of proved reserves, future net revenues and discounted future net revenues, set forth herein and in the Reserve Report. The Term NPI excludes production beyond the earlier of May 15, 2013 or such time as 41,683 MMcf of gas has been produced which is attributable to Eastern American's net revenue interests in the properties burdened by the Term NPI. The discounted present value of estimated future net revenues was determined using a discount rate of 10%. A copy of the Reserve Report is included as Exhibit A hereto.
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(1) Reserve volumes and estimated future net revenues for Underlying Properties reflect volumes and revenues distributable to Eastern American's entire net revenue interest with respect to the Underlying Properties.
(2) Includes 4,209 MMCF of proved reserves attributable to the 23 Development Wells drilled in 1996. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations."
(3) The effects of depreciation, depletion and federal income tax, including Section 29 Credits, have not been taken into account in estimating future net revenues. Estimated future net revenues and discounted estimated future net revenues are not intended, and should not be interpreted, as representing the fair market value for the estimated reserves.
Based on the Reserve Report, the proved gas reserves of the Trust include 1,183 MMCF of undeveloped gas reserves attributable to the 9 Development Wells that have not been drilled. Certain third parties have drilled wells in close proximity to the drill sites for five of the Development Wells that have not been drilled. Such wells may drain a portion of the gas reserves that otherwise would be expected to be produced by these five Development Wells following the drilling and completion of such Development Wells. The Reserve Report does not take into account any reduction of gas reserves attributable to the Development Wells that may have occurred as a result of drainage from these third-party wells. See "-- Regulation of Natural Gas."
The value of the Depositary Units and the Trust Units evidenced thereby are substantially dependent upon the proved reserves and production levels attributable to the Net Profits Interests. There are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the timing of development expenditures. The reserve data set forth herein, although prepared by independent engineers in a manner customary in the industry, are estimates only, and actual quantities and values of gas are likely to differ from the estimated amounts set forth
herein. In addition, the discounted present values shown herein were prepared using guidelines established by the Securities and Exchange Commission (the "Commission") and Financial Accounting Standards Board for disclosure of reserves and should not be considered representative of the market value of such reserves or the Depositary Units or the Trust Units evidenced thereby. A market value determination would include many additional factors.
DEFINITIONS
As used herein, the following terms have the meanings indicated: "Mcf" means thousand cubic feet of gas, "MMCF" means million cubic feet of gas, "Bbl" means barrel (approximately 42 U.S. gallons), and "MBbl" means thousand barrels.
COMPETITION AND MARKETS
All of the production attributable to the Net Profits Interest is sold to Eastern Marketing pursuant to the Gas Purchase Contract. See "The Net Profits Interests - - Gas Purchase Contract."
REGULATION OF NATURAL GAS
The natural gas industry has long been highly regulated by state and federal authorities. Concerns about perceived pipeline monopolies and other factors caused Congress to impose economic regulation on both pipelines and producers. Federal agencies regulated tariffs and conditions of service offered by interstate pipelines, and set maximum prices on the wellhead price of natural gas sold into interstate commerce. States, and even local governments, also regulated retail sales of natural gas by local utilities. Government agencies also set production rates to avoid waste and imposed environmental and safety regulations. At present, it appears that Federal regulation of wellhead natural gas prices has ended. However there can be no assurance that price controls or other similar economic regulations may not be reimposed in the future.
Drilling and production of natural gas are heavily regulated in Pennsylvania and West Virginia, as in most states. A well cannot be drilled without a permit, and operations must be conducted in compliance with environmental, safety and conservation laws and regulations. In contrast to many other states which have substantial oil and gas production activity, the spacing of shallow wells (such as the wells subject to the Net Profits Interests) is not regulated by any state statute or regulatory agency in either West Virginia or Pennsylvania. Without spacing requirements specified by state statute or regulation, drainage of reserves from a property may occur from wells located in close proximity to such property. Due to the cost of drilling and completing wells and the typical production characteristics of natural gas wells in these states, Eastern American believes that it is not generally economic to drill gas wells in close proximity to an existing gas well since the new well would not generally produce sufficient volumes of gas to provide a sufficient rate of return after taking into account drilling costs, completion costs and ongoing operating and marketing costs of such new well. As a result, Eastern American has historically not drilled development wells closer than 1,000 feet from an existing well. As described elsewhere herein, third parties have recently drilled wells within 1,000 feet of five of the undrilled Development Well sites. Eastern American intends to take such action as may be necessary to comply with its obligation to drill the Development Wells.
ENVIRONMENTAL REGULATION
GENERAL. Activities on the Underlying Properties are subject to existing Federal, state and local laws and regulations governing health, safety, environmental quality and pollution control. It is anticipated that, absent the occurrence of an extraordinary event, compliance with existing Federal, state and local laws, rules and regulations regulating health, safety, the discharge of materials into the environment or otherwise relating to the protection of the environment will not have a material adverse effect upon the Trust. It cannot be predicted what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from operations on the Underlying Properties could have on the Trust. However, pursuant to the terms of the Conveyances, any costs or expenses incurred in connection with environmental liabilities of Eastern American arising out of or related to activities occurring on or in, or conditions existing on or under, the Underlying Properties before the effective date of the Conveyances will be borne by Eastern American and will not be deducted in calculating Net Proceeds attributable to the Net Profits Interests. Additionally, because Unitholders will have limited liability in accordance with the Trust Agreement and Delaware law, Unitholders should be shielded from direct liability for any environmental liabilities. See "Description of
Trust Units and Depositary Units--Liability of Unitholders." However, costs and expenses incurred by Eastern American for certain Capital Costs associated with environmental liabilities arising after the effective date of the Conveyances would reduce Net Proceeds, and would therefore be borne, in part, by the Unitholders.
SOLID AND HAZARDOUS WASTE. The Underlying Properties include numerous properties that have produced gas for a number of years but in which Eastern American has held an interest for a relatively short period of time. Although, to Eastern American's knowledge, prior operators utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid or hazardous wastes may have been disposed of or released on or under the Underlying Properties. Federal, state and local laws applicable to gas-related wastes have become increasingly more stringent. Under these new laws, Eastern American or the operator of the Underlying Properties could be required to remove or remediate previously disposed wastes or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.
The operations of the Underlying Properties may generate wastes that are subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The Environmental Protection Agency (the "EPA") has limited the disposal options for certain hazardous wastes and may adopt more stringent disposal standards for nonhazardous wastes.
SUPERFUND. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known a the "superfund" law, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the current or previous owner and operator of a site and companies that disposed or arranged for the disposal of, the hazardous substance found at a site. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs of such action. In the course of their operations, the operators of the Underlying Properties have generated and will generate wastes that may fall within CERCLA's definition of "hazardous substances." Eastern American or the previous operator of the Underlying Properties may be responsible under CERCLA for all or part of the costs to clean up sites at which such substances have been disposed.
AIR EMISSIONS. The operations of the Underlying Properties are subject to Federal, state and local regulations concerning the control of emissions from sources of air contaminants. Administrative enforcement actions for failure to comply strictly with air regulations or permits are generally resolved by payment of a monetary penalty and correction of any identified deficiencies. Regulatory agencies could require the operators to forego or modify construction or operation of certain air emission sources.
OSHA. The operations of the Underlying Properties are subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and similar state statutes require that information be organized and maintained about hazardous materials used or produced in the operations. Certain of this information must be provided to employees, state and local government authorities and citizens.
DESCRIPTION OF TRUST UNITS AND DEPOSITARY UNITS
The following information is subject to the detailed provisions of the Deposit Agreement entered into by Eastern American, the Trustee, and Bank of Montreal Trust Company as Depositary (the "Depositary") and all holders from time to time of Depositary Units (the "Deposit Agreement"), which is incorporated by reference as an exhibit to this Form 10-K and is available upon request.
The functions of the Depositary under the Deposit Agreement are custodial and ministerial in nature and for the benefit of Unitholders. The Deposit Agreement and the issuance of Depositary Units thereunder provide Unitholders an administratively convenient form of holding an investment in the Trust and a Treasury Obligation. Each Depositary Unit is evidenced by a certificate, which is issued by the Depositary and transferable only in denominations of 50 Depositary Units or an integral multiple thereof. Accordingly, each holder of 50 Depositary Units will own a beneficial interest in 50 Trust Units and the entire beneficial interest in a discrete Treasury Obligation in a face amount of $1,000, or $20 per Depositary Unit.
The deposited Trust Units and Treasury Obligations are held solely for the benefit of the Unitholders and do not constitute assets of the Depositary or the Trust. The Depositary has no power to assign, transfer, pledge or otherwise dispose of any of the Trust Units or Treasury Obligations, except in the limited instances provided in the Deposit Agreement.
Generally, the Depositary Units are entitled to participate in distributions with respect to the Trust Units, the Treasury Obligations and to the liquidation of the remaining assets of the Trust.
WITHDRAWAL OF TRUST UNITS AND RESTRICTIONS ON TRANSFER
Upon presentation of Depositary Units in denominations of 50 or integral multiples thereof for withdrawal of the Trust Units and discrete Treasury Obligations evidenced thereby in accordance with the Deposit Agreement, the Unitholder will receive an uncertificated direct interest in Trust Units. These withdrawn Trust Units will be evidenced on the books of the Trustee by a transfer of such Trust Units from the name of the Depositary to the name of the withdrawing Unitholder. Holders of withdrawn Trust Units will be entitled to receive Trust distributions and periodic Trust information (including tax information) directly from the Trustee. Moreover, holders of Trust Units will be entitled to each of the rights accorded Unitholders under the Trust Agreement, including voting rights, as elsewhere described herein, except that withdrawn Trust Units are not freely transferable as described below.
Pursuant to the Trust Agreement and the transfer application for transfer of the Trust Units, withdrawn Trust Units are not transferable except by operation of law. A holder of withdrawn Trust Units may, however, transfer such Trust Units in denominations of 50 (or integral multiples thereof) to the Depositary for redeposit, together with Treasury Obligations in the face amount equal to $1,000 for each 50 Trust Units redeposited, in exchange for Depositary Units. Such redeposit may be effected by delivering written notice of such transfer jointly to the Depositary and the Trustee together with proper documentation necessary to transfer the requisite Treasury Obligations into the name of the Depositary.
DISTRIBUTIONS AND INCOME COMPUTATIONS
The Trustee will determine for each quarter the Quarterly Distribution Amount available for distribution to holders of Depositary Units and the Trust Units evidenced thereby. The Quarterly Distribution Amount will be equal to the excess, if any, of the cash received by the Trust, on or before the 15th day of the third month following the end of each calendar quarter ending prior to the dissolution of the Trust, from the Net Profits Interests then held by the Trust attributable to production during such quarter, plus, with certain exceptions, any other cash receipts of the Trust during such quarter, over the liabilities for the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. Based on the payment procedures relating to the Net Profits Interests, cash received by the Trustee in a particular quarter from the Net Profits Interests will reflect actual gas production for a portion of such quarter and a production estimate for the remainder of such quarter, such estimate to be adjusted to actual production in the following quarter. The Quarterly Distribution Amount for each quarter will be payable to Unitholders of record on the Quarterly Record Date, which will be the last day of the second month following the end of such calendar quarter or such later date as the Trustee determines is required to comply with legal or stock exchange requirements. It is expected that the Trustee will be able to distribute cash on or before the 15th day (or the next succeeding business day following such day if such day is not a business day) of the third month following the end of each calendar quarter to each person who was a Unitholder of record on the Quarterly Record Date, together with interest earned on such Quarterly Distribution Amount from the date of receipt thereof by the Trustee to the payment date.
The net taxable income of the Trust for each calendar quarter will be reported by the Trustee for tax purposes as belonging to the holders of record to whom the Quarterly Distribution Amount was or will be distributed. Assuming that the Trust will be classified for tax purposes as a "grantor trust," the net taxable income will be realized by the holders for tax purposes in the calendar quarter received by the Trustee, rather than in the quarter distributed by the Trustee. Taxable income of a holder may differ from the Quarterly Distribution Amount because the Treasury Obligations will be treated as generating interest income for tax purposes. There may also be minor variances because of the possibility that, for example, a reserve will be established in one quarter that will not give rise to a tax deduction until a subsequent quarter, an expenditure paid for in one quarter will have to be amortized for tax purposes over several quarters, etc. See "Federal Income Tax Consequences".
Each holder of Depositary Units (including the underlying Trust Units) of record as of the record date for the final quarter
of the Trust's existence will be entitled to receive a liquidating distribution equal to a pro rata portion of the net proceeds from the sale of the Royalty NPI (to the extent not previously distributed) and a pro rata portion of the proceeds from the matured Treasury Obligations.
POSSIBLE DIVESTITURE OF DEPOSITARY UNITS AND TRUST UNITS
The Trust Agreement imposes no restrictions based on nationality or other status of holders of Trust Units. However, the Trust Agreement and the Deposit Agreement provide that in the event of certain judicial or administrative proceedings seeking the cancellation or forfeiture of any property in which the Trust has an interest because of the nationality, citizenship, or any other status, of any one or more holders of Trust Units including holders of Depositary Units, the Trustee will give written notice thereof to each holder whose nationality, citizenship or other status is an issue in the proceeding, which notice will constitute a demand that such holder dispose of his Depositary Units or withdrawn Trust Units within 30 days. If any holder fails to dispose of his Depositary Units or withdrawn Trust Units in accordance with such notice, cash distributions on such units are subject to suspension. In the event a holder fails to dispose of Depositary Units in accordance with such notice, the Depositary may cancel such holder's Depositary Units and reissue them in the name of the Trustee, whereupon the Trustee will use its reasonable efforts to sell the Depositary Units and remit the net sale proceeds to such holder. In the case of Trust Units withdrawn from deposit with the Depositary, the Trustee shall redeem such Trust Units not divested in accordance with such notice, for a cash price equal to the then-current market price of the Depositary Units less the then-current over-the-counter bid price of the related, withdrawn Treasury Obligations. The redemption price will be paid out in quarterly installments limited to the amount that otherwise would have been distributed in respect of such redeemed Trust Units.
LIABILITY OF UNITHOLDERS
Consistent with Delaware law, the Trust Agreement provides that the Unitholders will have the same limitation on liability as is accorded under the laws of such state to stockholders of a corporation for profit. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
LIQUIDATION OF THE TRUST
The Trust will be liquidated and the Royalty NPI will be sold prior to the Liquidation Date. Unitholders of record as of the record date for the final quarter of the Trust's existence will be entitled to receive a terminating distribution with respect to each Depositary Unit equal to a pro rata portion of the net proceeds from the sale of the Royalty NPI (to the extent not previously distributed) and a pro rata portion of the proceeds from the matured Treasury Obligations. Under the Trust Agreement, Eastern American has a right of first refusal to purchase the Royalty NPI at fair market value, or if applicable the offered third-party price, prior to the Liquidation Date.
FEDERAL INCOME TAX MATTERS
This section is a summary of Federal income tax matters of general application which addresses the material tax consequences of the ownership and sale of Depositary Units. Except where indicated, the discussion below describes general Federal income tax considerations applicable to individuals who are citizens or residents of the United States. Accordingly, the following discussion has only limited application to domestic corporations and persons subject to specialized Federal income tax treatment, such as tax-exempt entities (including IRAs), regulated investment companies and insurance companies. The following discussion does not address tax consequences to foreign persons. It is impractical to comment on all aspects of Federal laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in Depositary Units as they relate to the particular circumstances of every prospective Unitholder. EACH UNITHOLDER SHOULD CONSULT HIS OWN TAX ADVISOR WITH RESPECT TO HIS PARTICULAR CIRCUMSTANCES INCLUDING, PARTICULARLY, HIS ALTERNATIVE MINIMUM TAX CIRCUMSTANCES.
This summary is based on current provisions of the Internal Revenue Code of 1986, as amended (the "Code") existing and proposed regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the Internal Revenue Service ("IRS").
At the issuance of the Depositary Units, the Company obtained an opinion of counsel, based on certain representations and subject to certain qualifications, that, for Federal income tax purposes, (a) the Trust will be taxed as a grantor trust and not as an association taxable as a corporation, (b) the Term NPI will be taxed as a production payment, (c) the income from the Royalty NPI will be royalty income subject to the allowance for depletion, and (d) a Unitholder will be eligible to claim Section 29 Credits with respect to sales of gas production attributable to the Royalty NPI. The Trustee has reported the operations of the Trust consistent with these opinions.
No ruling has been or will be requested from the IRS with respect to any matter affecting the Trust or Unitholders, and thus no assurance can be provided that the statements set forth herein (which do not bind the IRS or the courts) will not be challenged by the IRS or will be sustained by a court if so challenged.
TREATMENT OF DEPOSITARY UNITS
A purchaser of a Depositary Unit will be treated, for Federal income tax purposes, as purchasing directly an interest in the Treasury Obligations and a Trust Unit. A purchaser will therefore be required to allocate the purchase price of his Depositary Unit between the interest in the Treasury Obligations and the Trust Unit in the proportion that the fair market value of each bears to the fair market value of the Depositary Unit. Information regarding purchase price allocations will be furnished to Unitholders by the Trustee.
CLASSIFICATION AND TAXATION OF THE TRUST
The Trust is expected to be treated as a grantor trust and not as an association taxable as a corporation. Consequently, the Trust will not be subject to tax. For tax purposes, Unitholders will be considered to own and receive the Trust's assets and income as though no trust were in existence. The Trust will file an information return, reporting all items of income, credit or deduction which must be included in the tax returns of the Unitholders. If the Trust were determined to be an association taxable as a corporation, it would be treated as a separate entity subject to corporate tax on its taxable income, Unitholders would be treated as shareholders, and distributions to Unitholders from the Trust would be treated as nondeductible corporate distributions. Such distributions would be taxable to a Unitholder, first, as dividends to the extent of the Unitholder's pro rata share of the Trust's earnings and profits, then as a tax-free return of capital to the extent of his basis in his Trust Units, and finally as capital gain to the extent of any excess.
DIRECT TAXATION OF UNITHOLDERS
Assuming that the Trust will be treated as a trust for Federal income tax purposes, and a Unitholder will be treated for Federal income tax purposes as owning a direct interest in the Treasury Obligations and the assets of the Trust, each Unitholder will be taxed directly on his pro rata share of the income attributable to the Treasury Obligations and the assets of the Trust and will be entitled to claim his pro rata share of the deductions and credits attributable to the Trust (subject to certain limitations discussed below). Income, credits and expenses attributable to the assets of the Trust and the Treasury Obligations will be taken into account by Unitholders consistent with their method of accounting and without regard to the taxable year or accounting method employed by the Trust.
The Trust makes quarterly distributions to Unitholders of record on each Quarterly Record Date. The terms of the Trust Agreement, as described below, seek to assure to the extent practicable that taxable income attributable to such distributions will be reported by the Unitholder who receives such distribution, assuming that he is the owner of record on the Quarterly Record Date. In certain circumstances, however, a Unitholder will not receive the distribution attributable to such income. For example, if the Trustee establishes a reserve or borrows money to satisfy liabilities of the Trust, income associated with the cash used to establish that reserve or to repay that loan must be reported by the Unitholder, even though that cash is not distributed to him. In addition, Unitholders will be required to recognize certain interest income attributable to the Treasury Obligations with respect to which no current cash distributions will be made.
The Trust allocates income, deductions and credits to Unitholders based on record ownership at Quarterly Record Dates. The IRS could require income and deductions of the Trust to be determined and allocated daily or require some method of daily proration, which could result in an increase in the administrative expenses of the Trust.
It is anticipated that total distributable cash will exceed taxable income through 2004. After 2004, taxable income will exceed distributable cash, and the amount of such excess could be significant. Such estimates are based on numerous assumptions as to the allocation of a Unitholder's purchase price and the amount and treatment of operating costs, development costs, Trust administrative expenses, production estimates and depletion. No assurance can be given that the estimates will prove to be correct, and the actual percentages could be materially higher or lower.
TREATMENT OF TRUST UNITS
Assuming that the Trust is treated as a trust for tax purposes, each Unitholder will be treated as purchasing directly an interest in the Net Profits Interests. The purchaser of a Depositary Unit will be required to allocate the portion of his total purchase price allocated to the Trust Unit between the Royalty NPI and the Term NPI in the proportion that the fair market value of each bears to the total fair market value of both. Information regarding purchase price allocations will be furnished to Unitholders by the Trustee.
INTEREST INCOME
The Term NPI will be treated as a "production payment" under Section 636(a) of the Code. Thus, each Unitholder will be treated as making a mortgage loan on the Underlying Properties of the Term NPI to Eastern American in an amount equal to the amount of the purchase price of each Depositary Unit allocated to the Term NPI. Because it is treated as a debt instrument for tax purposes, the Term NPI will be subject to the original issue discount income ("OID") rules of the Code which generally require the periodic inclusion of the original issue discount in income of the purchaser of a debt instrument. The Code also authorizes the IRS to prescribe regulations modifying the statutory provisions where, by reason of contingent payments such as those provided for by the Term NPI, the tax treatment provided under the Code provisions does not carry out the purposes of such provisions. In early 1994, the IRS issued final regulations regarding the income tax treatment of debt instruments with original issue discount.
The IRS has issued a series of proposed regulations dealing with debt instruments which call for contingent payments. The initial set of proposed regulations dealing with this topic were issued on April 8, 1986, and modified on February 26, 1991 (the "Old Proposed Regulations"). A second set of proposed contingent payment regulations were issued on January 19, 1993, but were withdrawn prior to publication in the Federal Register. On December 15, 1994, the IRS replaced the Old Proposed Regulations by issuing a third set of proposed regulations addressing debt obligations that provide for contingent payments (the "New Proposed Regulations"). The New Proposed Regulations are proposed to be effective for debt obligations issued on or after the date that is sixty days following the promulgation of these regulations in final form. Thus, by their terms, the New Proposed Regulations do not apply to the Term NPI. Due to the withdrawal of the Old Proposed Regulations, there are no final or proposed Treasury Regulations which offer regulatory guidance in respect to contingent debt obligations issued prior to the effective date of the New Proposed Regulations.
The New Proposed Regulations require that the issuer construct a "projected" payment schedule based on the fixed payments due and the projections of all contingent payments that may become due under the obligation. Accruals of interest expense and income are then determined based on the projected schedule, with adjustments to reflect the actual contingent payments when they are paid. If the IRS determines that contingent payment debt issued prior to the effective date of the New Proposed Regulations, such as the Term NPI, should be taxed similar to the manner provided in the New Proposed Regulations, it would likely have the effect of accelerating the recognition of income attributable to the Term NPI. In such a case, if such determination by the IRS were ultimately upheld, Unitholders who reported interested income attributable to the Term NPI consistent with Eastern American's approach (described below) could owe additional tax, along with interest and penalties on such additional tax.
In light of the lack of regulatory guidance on this issue, Eastern American, as obligor under the Term NPI, intends to continue to treat the Term NPI in the manner provided under the Old Proposed Regulations, which were proposed at the time the Term NPI was transferred to the Trust and Trust Units were issued. Under this approach, each payment (at the time the amount of such payment becomes fixed) made to the Trust with respect to the Term NPI will be treated first as a payment of interest to the extent of interest deemed accrued under the OID rules and the excess (if any) will be treated as a payment of principal. The total amount treated as principal will be limited to a portion of the purchase price of each Depositary Unit allocated to the Term NPI. For purposes of determining the amount of accrued interest, the Old Proposed Regulations required the use of the Applicable Federal Rate based on the due date of the final payment due under the terms of the production payment, which for the Term NPI is May 15, 2013.
Unitholders will also be required to recognize and report OID interest income attributable to the Treasury Obligations. In general, the total amount of OID a Unitholder will be required to recognize will be calculated as the difference between the amount of the purchase price of a Depositary Unit allocated to the Treasury Obligations and the pro rata portion of the face amount of such Treasury Obligations attributable to the Depositary Unit. The amount of OID so calculated will be included in income by a Unitholder on the basis of a constant interest rate computation.
ROYALTY INCOME AND DEPLETION
The income from the Royalty NPI will be royalty income subject to an allowance for depletion. The depletion allowance must be computed separately by each Unitholder for each oil or gas property (within the meaning of Code Section 614). The IRS presently takes the position that a net profits interest burdening multiple properties is one property for depletion purposes. Accordingly, the Trust intends to take the position that the Royalty NPI is one property for depletion purposes until such time as the issue is resolved in some other manner.
The allowance for depletion with respect to a property is determined annually and is the greater of cost depletion or, if allowable, percentage depletion. Percentage depletion is generally available to "independent producers" (generally persons who are not substantial refiners or retailers of oil or gas or their primary products) on the equivalent of 1,000 barrels of production per day. Percentage depletion is a statutory allowance equal to 15% of the gross income from production from a property which is included in income by a taxpayer.
Percentage depletion is subject to a net income limitation which is 100% of the taxable income from the property, computed without regard to depletion deductions and certain loss carrybacks. The percentage depletion deduction for a taxable year is limited to 65% of the taxpayer's taxable income for the year, before percentage depletion and certain other deductions. Unlike cost depletion, percentage depletion is not limited to the adjusted tax basis of the property, although it reduces that adjusted tax basis (but not below zero).
In computing cost depletion for each property for any year, the adjusted tax basis of that property at the end of that year is divided by the estimated total units (Mcf of gas) recoverable from that property to determine the per-unit allowance for such property. The per-unit allowance is then multiplied by the number of units produced and sold from that property during the year. Cost depletion for a property cannot exceed the adjusted tax basis of such property. Since the Trust will be taxed as a grantor trust, each Unitholder will compute cost depletion using his basis in his Trust Units allocated to the Royalty NPI. Information will be provided by the Trustee to each Unitholder reflecting how that basis should be allocated.
SECTION 29 CREDIT
Eastern American believes that most of the production attributable to the Royalty NPI is gas produced from Devonian shale or a tight formation. Provided a number of requirements are met, taxpayers are entitled to the Section 29 Credit for gas produced from Devonian shale or a tight formation. The Section 29 Credit generally applies only to gas produced from Devonian shale or a tight formation in the United States and sold to an unrelated party prior to January 1, 2003, from wells drilled after December 31, 1979, and prior to January 1, 1993. Additionally, the Section 29 Credit applies only to gas produced from a tight formation which, as of April 20, 1977, was committed or dedicated to interstate commerce (as defined in Section 2(18) of the Natural Gas Policy Act, as in effect on November 5, 1990), or which is produced from a well drilled after November 5, 1990. A Unitholder will be eligible to claim the Section 29 Credit with respect to sales of such gas attributable to the Royalty NPI.
Section 29 Credits resulting from an investment in Depositary Units may only be used to reduce a taxpayer's regular income tax liability. Section 29 Credits available to a taxpayer in any taxable year may not be carried back but may be carried forward for use by that taxpayer in a subsequent tax year only in a limited fashion. See "Alternative Minimum Tax" below.
OTHER INCOME AND EXPENSES
From time to time the Trust may generate interest income on funds held as a reserve or held until the next distribution date. Expenses of the Trust will include administrative expenses of the Trustee. Under the Code, certain miscellaneous itemized deductions of an individual taxpayer are deductible only to the extent that in the aggregate they exceed 2% of the taxpayer's adjusted gross income. Certain administrative expenses attributable to the Trust Units may have to be aggregated with an
individual Unitholder's other miscellaneous itemized deductions to determine the excess over 2% of adjusted gross income. To date the amount of such expenses has not been significant in relation to the Trust's income.
ALTERNATIVE MINIMUM TAX
The Code imposes a minimum tax (known as an "alternative minimum tax" or "AMT") on each taxpayer to the extent that his "tentative minimum tax" in any taxable year exceeds his regular tax for that year. For purposes of computing the AMT, the taxpayer's taxable income is recomputed with various "adjustments" plus "items of tax preference."
A taxpayer is generally entitled to a credit against, or reduction in, his regular tax liability in a subsequent year in an amount equal to the AMT he pays for a prior taxable year. That credit can only be used to reduce his regular tax liability for that subsequent year to the extent his regular tax liability for that subsequent year exceeds his tentative minimum tax liability for that subsequent year, however.
The Section 29 Credit allowable to a taxpayer as a reduction of his liability for any taxable year cannot exceed the excess of his regular tax liability for such taxable year, as reduced by his foreign tax credits and certain nonrefundable credits, over his tentative minimum tax liability for that year. Any amount of Section 29 Credit disallowed for the tax year solely because of this limitation will increase a taxpayer's credit for the prior year's AMT, as described above. There is no provision for the carryback or carryforward of the Section 29 Credit in any other circumstances. Therefore, a Unitholder may not receive the full benefit of available Section 29 Credits, depending on his particular AMT circumstances.
Since the effect of the AMT varies depending upon each Unitholder's personal tax and financial position, each Unitholder is advised to consult with his own tax advisor concerning the effect of the AMT on him and Section 29 Credits attributable to an investment in the Depositary Units.
NON-PASSIVE ACTIVITY
The income, credits and expenses of the Trust will not be taken into account in computing the passive activity losses and income under Code Section 469 for a Unitholder who acquires and holds Depositary Units as an investment and did not acquire them in the ordinary course of business.
UNRELATED BUSINESS TAXABLE INCOME
Certain organizations that are generally exempt from tax under Code Section 501 are subject to tax on certain types of business income defined in Code Section 512 as unrelated business income. The income of the Trust will not be unrelated business taxable income within the meaning of Code Section 512 so long as the Trust Units are not "debt-financed property" within the meaning of Code Section 524(b). In general, a Trust Unit would be debt-financed if the Unitholder incurs debt to acquire a Trust Unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if such Trust Unit had not been acquired. Legislative proposals have been made from time to time which, if adopted, would result in the treatment of income attributable to the Royalty NPI as unrelated business income.
SALE OF DEPOSITARY UNITS; SALE OF TRUST UNITS OR TREASURY OBLIGATIONS
Generally, a Unitholder will realize gain or loss on the sale or exchange of his Depositary Units measured by the difference between the amount realized on the sale or exchange and his adjusted basis for such Depositary Units. Gain or loss on the sale of Depositary Units by a Unitholder who is not a dealer with respect to such Depositary Units and who has a holding period for the Depositary Units of more than one year will be treated as long-term capital gain or loss except to the extent of the depletion recapture amount and any accrued market discount as explained below. A Unitholder's initial basis in his Depositary Units will be equal to the amount paid for such Depositary Units. Such basis will be increased by the amount of OID income recognized by the Unitholder attributable to the Treasury Obligations. Such basis will be reduced by deductions for depletion claimed by the Unitholder (but not below zero). In addition, such basis will be reduced by the amount of any payments attributable to the Term NPI which are treated as payments of principal under the OID rules.
For Federal income tax purposes, the sale of a Depositary Unit will be treated as a sale by the Unitholder of his interest in the Treasury Obligations and the assets of the Trust. Thus, upon the sale of Depositary Units, a Unitholder must treat as ordinary income his depletion recapture amount, which is an amount equal to the lesser of (i) the gain on that sale attributable to disposition of the Royalty NPI or (ii) the sum of the prior depletion deductions taken with respect to the Royalty NPI (but not in excess of the initial basis of such Depositary Units allocated to the Royalty NPI). It is possible that the IRS would take the position that a portion of the sales proceeds is ordinary income to the extent of any accrued income at the time of sale allocable to the Depositary Units sold, but which is not distributed to the selling Unitholder.
A Unitholder who allocates his purchase price (or is required to allocate his purchase price) to the Treasury Obligations in an amount less than the sum of (a) his share of the initial issue price of the Treasury Obligations and (b) his share of OID income recognized by prior holders of the Treasury Obligations (any such difference represents "market discount") will generally be required to recognize ordinary income to the extent of any accrued market discount upon sale of the Depositary Units. In general, accrued market discount is an amount which bears the same ratio to total market discount as the number of days which a Unitholder holds a Depositary Unit bears to the number of days after the date the Unitholder acquired the Depositary Unit and up to and including the Liquidation Date.
WITHDRAWAL OF TRUST UNITS OR TREASURY OBLIGATIONS
A Unitholder will recognize no gain or loss upon the withdrawal of the Trust Units or Treasury Obligations from the Depositary. A sale of the Trust Units or the Treasury Obligations will result in the recognition of income or loss.
SALE OF NET PROFITS INTERESTS OR PRODUCTION PAYMENT
A sale by the Trust of Net Profits Interests will be treated for Federal income tax purposes as a sale of Net Profits Interests by a Unitholder. Thus, a Unitholder will recognize gain or loss on a sale of Net Profits Interests by the Trust. A portion of that income may be treated as ordinary income to the extent of depletion recapture. Receipt by the Trust of proceeds drawn from the letter of credit supporting Eastern Marketing's obligations under the Gas Purchase Contract will, in certain cases, be in consideration for the conveyance to Eastern Marketing of a production payment interest in reserves attributable to the Net Profits Interests or to compensate the Trust for damages from a breach of the Gas Purchase Contract. All or a portion of such proceeds may be treated as non-taxable loan proceeds attributable to a loan by Eastern Marketing resulting from the production payment, may be treated as ordinary income not subject to depletion or may receive some other treatment, depending upon facts existing at that time. To the extent receipt of such proceeds is attributable to a sale of reserves by the Trust, depletion and Section 29 Credits available to the Unitholders for subsequent periods will be reduced.
BACKUP WITHHOLDING
In general, distributions of Trust income will not be subject to "backup withholding" unless (i) the Unitholder is an individual or other noncorporate taxpayer and (ii) such Unitholder fails to comply with certain reporting procedures.
TAX SHELTER REGISTRATION
The Trust has been registered with the IRS as a "tax shelter," and has received tax shelter registration number 93040000163. A "tax shelter," for purposes of the registration requirement, is an investment with respect to which a person could reasonably infer, from the representations made in connection with any offer for sale of any interest in the investment, that the "tax shelter ratio" for any investor may be greater than two to one as of the close of any of the first five years ending after the date on which the investment is offered for sale. The term "tax shelter ratio" with respect to an investment means the ratio that the aggregate amount of gross deductions for any investor, determined without regard to income derived from the investment, plus 350% of the credits that are potentially available to an investor, bears to the investment base for the year. The "investment base" is equal to the cash, plus the adjusted basis (which may be less than the fair market value) of any other property invested. Certain borrowings, however, including those from other participants in the venture, are excluded from the investment base. While Eastern American has no knowledge of any such borrowings, it is possible that, due to such borrowings, the investment base of an investor would be substantially reduced or eliminated.
A Unitholder who sells or otherwise transfers a Trust Unit must furnish to the transferee the tax shelter registration number set forth above. The penalty for failure of the transferor of a Trust Unit to furnish such tax shelter registration number to a
transferee is $100 for each such failure. Unitholders must disclose the tax shelter registration number of the Trust on Form 8271 to be attached to the tax return on which any deduction, loss, credit or other benefit generated by the Trust is claimed or income of the Trust is included. A Unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for such failure, will be subject to a $50 penalty for each such failure. (Any penalties discussed herein are not deductible for income tax purposes.)
ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THIS INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.
REPORTS
Unitholders of record will be provided informational tax packages in order to permit computation of their taxable income from ownership of Depositary Units.
STATE TAX CONSIDERATIONS
The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting individual Unitholders. Unitholders are urged to consult their own legal and tax advisors with respect to these matters.
The Trust owns the Net Profits Interests burdening the Underlying Properties located in the states of Pennsylvania and West Virginia. Both of these states have income taxes applicable to individuals and may require the Trust to withhold taxes from distributions made to nonresident Unitholders. Withholding, if required, is at the rate of 4% of taxable income attributable to West Virginia and 2.8% of taxable income attributable to Pennsylvania. A Unitholder may be required to file state income tax returns and/or to pay taxes in these states and may he subject to penalties for failure to comply with such requirements. Any state income taxes withheld by the Trust are treated as deductions against income in the calculation of income taxes otherwise payable.
The Depositary will provide information prepared by the Trustee concerning the Depositary Units sufficient to identify the income from Depositary Units that is allocable to each state. Unitholders of Depositary Units should consult their own tax advisors to determine their income tax filing requirements with respect to their share of income of the Trust allocable to states imposing a tax on such income.
The Trust Units may constitute real property or an interest in real property under the inheritance, estate and probate laws of either or both of Pennsylvania and West Virginia. If the Depositary Units are held to be real property or an interest in real property under the laws of a state in which the Underlying Properties are located, the holders of Depositary Units may be subject to devolution, probate and administration laws, and inheritance or estate and similar taxes, under the laws of such state.
Item 2.

Item 2. PROPERTIES.
Reference is made to Item 1 of this Form 10-K.
Item 3.

Item 3. LEGAL PROCEEDINGS.
There are no pending legal proceedings to which the Trust is a party.
Item 4.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF UNITHOLDERS.
There were no matters submitted to a vote of Unitholders during the quarter ended December 31, 1996.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED MATTERS.
The Depositary Units are traded on the New York Stock Exchange under the ticker symbol "NGT". The high and low prices and distribution paid during the quarters in the three-year period ended December 31, 1996 were as follow
QUARTER DISTRIBUTIONS 1994: HIGH LOW PAID - ----------------------------------- -------- -------- -------- First (to March 31, 1994) ......... $ 24 7/8 $ 21 3/8 $ 0.46 Second (to June 30, 1994) ......... $ 21 7/8 $ 19 3/4 $ 0.48 Third (to September 30, 1994) ..... $ 20 3/8 $ 18 $ 0.44 Fourth (to December 31, 1994) ..... $ 19 1/4 $ 14 3/4 $ 0.44
1995: First (to March 31, 1995) ......... $ 17 3/4 $ 15 1/4 $ 0.39 Second (to June 30, 1995) ......... $ 17 7/8 $ 16 1/4 $ 0.39 Third (to September 30, 1995) ..... $ 16 1/4 $ 14 3/4 $ 0.38 Fourth (to December 31, 1995) ..... $ 17 $ 14 7/8 $ 0.43
1996: First (to March 15, 1996) ......... $ 17 3/4 $ 16 $ 0.39 Second (to June 30, 1996) ......... $ 17 $ 14 3/8 $ 0.46 Third (to September 30, 1996) ..... $ 17 $ 14.75 $ 0.45 Fourth (to December 31, 1996) ..... 17 7/8 16 1/8 $ 0.46
At March 24, 1997 the 5,900,000 Depositary Units outstanding were held by 446 Unitholders of record.
With respect to the Treasury Obligations, the high and low asked prices per $1,000 face amount for the period from October 1, 1996 to December 31, 1996 were $345.43 and $312.30 respectively. The closing asked price on December 31, 1996 was $331.64 per $1,000 face amount.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA.
- ----------------------- (1) $0.51 of the $2.00 in distributions on the Units has been classified as a return of capital.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
GENERAL
The Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Net Profits Interests, to distribute to Unitholders cash which the Trust receives in respect of the Net Profits Interests and to perform certain administrative functions in respect of the Net Profits Interests and the Depositary Units. The Trust derives substantially all of its income and cash flows from the Net Profits Interests.
As of December 31, 1996, Eastern American had drilled a total of 56 Development Wells. Eastern American is required to drill 3 additional Developmental Wells by March 31, 1997 and 6 more during the remainder of 1997. All of the Development Wells are on line and producing natural gas.
During the second quarter of 1996, Eastern American identified seven (7) wells in which the Trust owned a Net Profit Interest which were no longer commercially productive. Pursuant to conveyances Eastern American has the right to abandon any well or working interest included in the Underlying Properties, if, in its opinion, such well or property ceases to produce or is not capable of producing in commercial paying quantities. The costs of plugging and abandonment is generally a deduction in the Net Proceeds calculation, but because Eastern American has identified an individual who agreed to pay such costs the Trust did not bear any of such costs.
During the fourth quarter of 1995, two of the wells in which the Trust owns a Net Profits Interest (identified as the Berwind No. 19 and Berwind No. 20 wells) were required to be plugged and abandoned by the coal lessee of the property upon which the wells were drilled since the wells interfered with proposed coal mining operations. The coal lessee could cause these wells to be plugged and abandoned pursuant to an agreement entered into prior to the formation of the Trust. This prior agreement is a Permitted Encumbrance under the Conveyances and the Trust accepted its Net Profits Interest subject to this prior agreement. Pursuant to this prior agreement the coal lessee is required to pay for the wells it causes to be plugged and abandoned and as a result Eastern American received $216,500 for the Berwind No. 19 and Berwind No.20 wells. Ninety percent (90%) of this amount or $194,850 was allocated to the Trust.
During the fourth quarter of 1994, one of the wells in which the Trust owns a Net Profits Interest was sold free and clear of the Net Profits Interest. The well that was sold is identified as the Moates No. 1 well situated in West Virginia. The well was sold to Weyerhaeuser Corporation ("Weyerhaeuser") who is the fee owner of the property. Weyerhaeuser advised Eastern American of its interest in acquiring the well since it was building a processing plant encompassing the well site.
During the third quarter of 1993, one of the wells in which the Trust owns a Net Profits Interest was sold free and clear of the Net Profits Interest. The well that was sold is identified as the Bethlehem Steel No. 25 well situated in West Virginia. The well was sold to Fola Land Company, Inc. ("Fola") who is the fee owner of the property upon which the well is situated. Fola advised Eastern American of its interest in acquiring the well since it was planning a strip mine in the general area of the well. The subject well is located in a valley surrounding the mine area, therefore, additional capital costs would have been required by the Trust and Eastern American to protect the integrity of the well.
Pursuant to the Trust Agreement, Eastern American may, without the consent of the Unitholders, require the Trust to release or convey the Net Profits Interest associated with any well, provided that the Net Profits Interest associated with such well accounts for no more than .25% of the total production from the Underlying Properties for the prior twelve (12) months. On a pro forma basis, the production from the Moates No. 1 well represented .19% of the total production from the Underlying Properties. The well was sold to Weyerhaeuser for the sum of $241,800, with 90% of the proceeds (or $217,620) being allocable to the Trust.
On a pro forma basis, the production from the Bethlehem Steel No. 25 well represented .15% of the total production from the Underlying Properties. The well was sold to Fola for the sum of $57,061, with 90% of the proceeds (or $51,355) being allocable to the Trust. As a result of the sale of the Moates No. 1 and the Bethlehem Steel No. 25, and the plugging and abandonment of the Berwind No. 19 and Berwind No. 20 wells, the Operating Cost Charge paid by the Trust has been accordingly reduced.
LIQUIDITY AND CAPITAL RESOURCES
The Trust has no source of liquidity or capital resources other than the distributions received from the Net Profits Interests.
In accordance with the provisions of the Conveyances, generally all revenues received by the Trust, net of Trust administrative expenses and the amount of established reserves, are distributed currently to the Unitholders.
RESULTS OF OPERATIONS
1996 COMPARED WITH 1995
The Trust's total distributions declared per Unit were $1.76 for the twelve months ended December 31, 1996 as compared to $1.58 for the twelve months ended December 31, 1995. Such increase was due to an increase in the price payable to the Trust under the Gas Purchase Contract ($3.00 per Mcf for the twelve months ended December 31, 1996; $2.67 per Mcf for the twelve months ended December 31, 1995) which was offset slightly by a decrease in production of gas attributable to the Net Profits Interests for the twelve months ended December 31, 1996 (4,028 MMcf) as compared to the production for the twelve months ended December 31, 1995 (4,032 MMcf). The production decreases were attributable to normal production declines associated with the Underlying Properties, which were only partially offset by the production from the Development Wells drilled.
The price payable to the Trust for gas production attributable to the Net Profits Interests was $3.00 per Mcf for the twelve months ended December 31, 1996 and $2.67 per Mcf for the twelve months ended December 31, 1995. The price per Mcf was higher for the twelve months ended December 31, 1996 than for the corresponding prior twelve months period due to a higher Fixed Price component of the Index Price under the Gas Purchase Contract ($3.08 per Mcf for the twelve months ended December 31, 1996, $2.93 per Mcf for the twelve months ended December 31, 1995). Such higher Fixed Price was attributable to the 5% annual escalation between years during the Primary Term. The Variable Price component was also higher ($2.88 per Mcf for the twelve months ended December 31, 1996, $2.14 per MCF for the twelve months ended December 31, 1995). Such higher Variable Price was directly attributable to an increase in the average futures spot market prices for gas delivered at the Henry Hub for the twelve months ended December 31, 1996 ($2.32 per Mcf) as compared to the prior year ($1.65 per Mcf).
1995 COMPARED WITH 1994
The Trust's total distributions declared per Unit were $1.58 for the twelve months ended December 31, 1995 as compared to $1.82 for the twelve months ended December 31, 1994. Such decrease was due to a decrease in production of gas attributable to the Net Profits Interests for the twelve months ended December 31, 1995 (4,032 MMcf) as compared to the production for the twelve months ended December 31, 1994 (4,481MMcf) as well as a decrease in the price payable to the Trust under the Gas Purchase Contract for the twelve months ended December 31, 1995 ($2.67 per Mcf) compared to the price for the twelve months ended December 31, 1994 ($2.72 per Mcf). The production decreases are attributable to normal production declines associated with the Underlying Properties, which were only partially offset by the production from the Development Wells drilled.
The price payable to the Trust for gas production attributable to the Net Profits Interests was $2.67 per Mcf for the twelve months ended December 31, 1995 and $2.72 per Mcf for the twelve months ended December 31, 1994. The price per Mcf was lower for the twelve months ended December 31, 1995 than for the corresponding prior twelve month period even though there was a higher Fixed Price component to the Index Price under the Gas Purchase Contract ($2.93 per Mcf for the twelve months ended December 31, 1995, $2.79 per Mcf for the twelve months ended December 31, 1994). Such a higher Fixed Price is attributable to the 5% annual escalation between years during the Primary Term. The Variable Price component was significantly lower ($2.14 per Mcf for the twelve months ended December 31, 1995, $2.58 per Mcf for the twelve months ended December 31, 1994). Such lower Variable Price is directly attributable to a decrease in the average futures spot market prices for gas delivered at the Henry Hub for the twelve months ended December 31, 1995 ($1.65 per Mcf) as compared to the prior year ($2.04 per Mcf).
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The Trust has no directors or executive officers. The Trustee is a corporate trustee which may be removed by the affirmative vote of holders a majority of the Trust Units then outstanding at a meeting of the Unitholders of the Trust at which a quorum is present.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION.
The Trust has no officers or directors, and is administered by the Trustee. For the years ended December 31, 1996, 1995 and 1994, the Trustee received $208,787, $246,817 and $212,039, respectively, as compensation for such services.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Security Ownership of Certain Beneficial Owners.
Based on filings with the Securities and Exchange Commission, the Trust is not aware of any person owning beneficially more than five percent of the Units as of March 15, 1997.
(b) Security Ownership of Management.
Not applicable.
(c) Changes in Control.
The Trust knows of no arrangements, including the pledge of securities of the Trust, the operation of which may at a subsequent date result in a change control of the Trust.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A)(1) FINANCIAL STATEMENTS
The following financial statements are included in this Annual Report on Form 10-K on the pages indicated: PAGE IN THIS FORM 10-K
Report of Independent Accountants........................................ B-2 Statements of Assets, Liabilities and Trust Corpus as of December 31, 1996 and 1995....................................................... B-3 Statements of Distributable Income for the years ended December 31, 1996, 1995 and 1994.................................. B-4 Statements of Changes in Trust Corpus for the years ended December 31, 1996, 1995 and 1994 .................................. B-5 Notes to Financial Statements............................................ B-6
(A)(2) SCHEDULES
All schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
(A)(3) EXHIBITS
All exhibits are incorporated: herein by reference to the indicated exhibits to filings previously made by the registrant with the Securities and Exchange Commission. All references are to the registrant's Registration Statement on Form S-1, Registration No. 33-56336, except for Exhibit 3(a), which is incorporated by reference to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994.
EXHIBIT NUMBER ------- 3(a) Second Amended and Restated Trust Agreement of Eastern American Natural Gas Trust................................... 3.1 4.1 Specimen Depositary Receipt.................................. 4.1 4.2 Form of NPI Royalty Deposit Agreement........................ 4.2 10.1 Form of Conveyance........................................... 10.1 10.2 Form of Term NPI Conveyance.................................. 10.2 10.3 Form of Gas Purchase Contract between Eastern American Energy Corporation, Eastern American Marketing Corporation and Eastern American Natural Gas Trust....................... 10.3 10.4 Form of Letter of Credit issued by The Chase Manhattan Bank to Eastern American Natural Gas Trust, as beneficiary........ 10.4 10.5 Form of Conveyance of Production Payment/Assignment of Production from Eastern American Natural Gas Trust to Eastern American Marketing Corporation....................... 10.5 10.6 Form of Assignment and Standby Performance Agreement......... 10.6
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange Commission during the quarter ended December 31, 1996.
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 ON THIS 31ST DAY OF MARCH 1997.
EASTERN AMERICAN NATURAL GAS TRUST
By: Bank of Montreal Trust Company, Trustee
By: /s/ E. KAY LIEDERMAN E. Kay Liederman Vice President
The Registrant, Eastern American Natural Gas Trust, has no principal executive officer, principal financial officer, controller or principal accounting officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided.
EASTERN AMERICAN NATURAL GAS TRUST
----------
FINANCIAL STATEMENTS
as of December 31,1996, and 1995 and for the years ended December 31, 1996, 1995 and 1994
REPORT OF INDEPENDENT ACCOUNTANTS
To the Unitholders and Bank of Montreal Trust Company, as Trustee for Eastern American Natural Gas Trust:
We have audited the accompanying statements of assets, liabilities and trust corpus of Eastern American Natural Gas Trust (the "Trust") as of December 31, 1996 and 1995, and the related statements of distributable income, and changes in trust corpus for the years ending December 31, 1996, 1995 and 1994. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in Note 2 to the financial statements, these financial statements have been prepared on a comprehensive basis of accounting other than generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Trust as of December 31, 1996 and 1995, and the distributable income for the years ended December 31, 1996, 1995 and 1994, on the basis of accounting described in Note 2.
Denver, Colorado March 20, 1997
B-2
EASTERN AMERICAN NATURAL GAS TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS as of December 31, 1996 and 1995 ----------
The accompanying notes are an integral part of these financial statements
B-3
EASTERN AMERICAN NATURAL GAS TRUST STATEMENTS OF DISTRIBUTABLE INCOME for the years ended December 31, 1996, 1995 and 1994 ----------
The accompanying notes are an integral part of these financial statements
B-4
EASTERN AMERICAN NATURAL GAS TRUST STATEMENTS OF CHANGES IN TRUST CORPUS for the years ended December 31, 1996, 1995 and 1994 ----------
The accompanying notes are an integral part of these financial statements
B-5
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS ----------
1. ORGANIZATION OF THE TRUST
The Eastern American Natural Gas Trust (the "Trust") was formed under the Delaware Business Trust Act pursuant to a Trust Agreement (the "Trust Agreement") among Eastern American Energy Corporation ("Eastern American"), as grantor, Bank of Montreal Trust Company, as Trustee (the "Trustee"), and Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee"). The purpose of the Trust is to acquire and hold net profits interests owned by Eastern American in 650 producing gas wells and 65 proved development well locations in West Virginia and Pennsylvania (the "Underlying Properties"). The Underlying Properties are operated by Eastern American. The Net Profits Interests (the "Net Profits Interests") consist of a Royalty interest in 322 wells and a Term interest in the remaining wells and locations. As of December 31, 1994, Eastern American had drilled fifteen development wells, during 1995 drilled an additional eighteen wells and during 1996 drilled an additional twenty-three wells for a total of fifty-six development wells drilled as of December 31, 1996. All of these wells are producing natural gas. No additional costs were charged to the Trust for the fifty-six wells drilled through 1996 nor will there be any additional costs for the nine locations remaining to be drilled. Eastern American is required to drill three additional development wells by March 31, 1997 and six more during the remainder of 1997. On or before May 15, 2013, the Trustee is required to sell the royalty interests and liquidate the Trust.
On March 15, 1993, 5,900,000 depositary units were issued in a public offering at an initial public offering price of $20.50 per depositary unit. Each depositary unit consists of beneficial ownership of one unit of beneficial interest ("Trust Unit") in the Trust and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon United States Treasury Obligation ("Treasury Obligation") maturing on May 15, 2013 (see Note 6). Of the net proceeds from such offering, $27,787,820 was used to purchase $118,000,000 in face amount of Treasury Obligations and $93,162,180 was paid to Eastern American in consideration for the conveyance of the Net Profits Interests to the Trust. The Trust acquired the Net Profits Interests effective as of January 1, 1993.
The Net Profits Interests are passive in nature, and neither the Trustee nor the Delaware Trustee has management control or authority over, nor any responsibility relating to, the operation of the properties subject to the Net Profits Interests. The Trust Agreement provides, among other things, that the Trust shall not engage in any business or commercial activity or acquire any asset other that the Net Profits Interests initially conveyed to the Trust; the Trustee may establish a reserve for payment of any liability which is contingent, uncertain in amount or that is not currently due and payable; the Trustee is authorized to borrow funds required to pay liabilities of the Trust, provided that such borrowings are repaid in full prior to further distributions to Unitholders; and the Trustee will make quarterly cash distributions to Unitholders from funds of the Trust.
B-6
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
2. SIGNIFICANT ACCOUNTING POLICIES:
The following is a summary of the significant accounting policies followed by the Trust.
Basis of Accounting:
The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles because certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with generally accepted accounting principles. In addition, amortization of the Net Profits Interests in gas properties is charged directly to Trust Corpus.
Net Profits Interests in Gas Properties:
The Net Profits Interests in gas properties are periodically assessed to determine whether their net capitalized cost is impaired. The Trust will determine if a writedown is necessary to its investment in the Net Profits Interests in gas properties to the extent that total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. The Trust will then provide a writedown to fair market value. Any such writedown would not reduce distributable income, although it will reduce Trust Corpus.
Significant dispositions of the Underlying Properties are charged to Net Profits Interests and the Trust Corpus.
Amortization of the Net Profits Interests in gas properties is calculated on a units-of- production basis, whereby the Trust's cost basis in the properties is divided by total Trust 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.
Revenues 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 elections of the Unitholders. Thus, the Statements of Distributable Income purport to show distributable income, defined as Trust income available for distribution to Unitholders before application of those Unitholders additional expenses, if any, for depletion, interest income and expense, and income taxes.
B-7
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
2. SIGNIFICANT ACCOUNTING POLICIES, CONTINUED:
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 also recognized on an accrual basis. The payment provisions of the gas purchase contract between the Trust and Eastern Marketing Corporation require payment with respect to gas production for a calendar quarter to be made to the Trust on or before the tenth day of the third month following such quarter.
Use of Estimates in the Preparation of Financial Statements.
The preparation of financial statements requires management 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.
3. INCOME TAXES:
Tax counsel has advised the Trust that, under current tax laws, the Trust will be classified as a grantor trust for federal and state income tax purposes and, therefore, is not subject to taxation at the trust level. Accordingly, no provision for federal or state income taxes has been made. However, the opinion of tax counsel is not binding on taxing authorities.
The Unitholders are considered, for income tax purposes, to own the Trust's income and principal as though no trust were in existence. Thus, the taxable year for reporting a Unitholder's share of the Trust income, expense and credit is controlled by the Unitholder's taxable year and method of accounting, not the taxable year and method of accounting employed by the Trust.
4. DISTRIBUTIONS TO UNITHOLDERS:
The Trustee determines for each quarter the amount available for distribution to the Unitholders. Such amount will be equal to the excess if any of the cash received by the Trust, on or before the tenth day of the third month following the end of each calendar quarter, ending prior to the dissolution of the Trust, from the Net Profits Interests then held by the Trust attributable to production during such quarter, plus, with certain exceptions, any other cash receipts of the Trust during such quarter, over the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. Cash received by the Trustee in a particular quarter from the Net Profits Interests will reflect actual gas production for a portion of such quarter and a production estimate for the remainder of such quarter, such estimate to be adjusted to actual production in the following quarter.
B-8
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
DISTRIBUTIONS TO UNITHOLDERS, CONTINUED:
Net proceeds receivable included in the Statement of Assets, Liabilities and Trust Corpus as of December 31, 1996 and December 31, 1995 was received by the Trust and distributed to the Unitholders on March 15, 1997 and 1996, respectively.
5. RELATED PARTY TRANSACTIONS:
The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees, printing costs and other administrative expenses incurred at the direction of the Trustee. The total of all Trustee fees and Trust administrative expenses was $208,787 for the year ended December 31, 1996, $246,817 for the year ended December 31, 1995 and $212,039 for the year ended December 31, 1994. The Trustee paid Eastern American an annual base fee of $210,000 which increases by 3.5% per year, payable quarterly, to reimburse Eastern American for overhead expenses. The Trustee paid Eastern American $232,832, $224,957 and $217,350 for overhead expenses for 1996, 1995 and 1994, respectively. Operating cost charges included in the Statement of Distributable Income are paid to Eastern American.
Gas production attributable to the Net Profits Interests is purchased from the Trust by Eastern Marketing Corporation ("Eastern Marketing"), a wholly owned subsidiary of Eastern American, pursuant to a Gas Purchase Contract which effectively commenced as of January 1, 1993 and expires upon the termination of the Trust.
Pursuant to the Gas Purchase Contract, Eastern Marketing is obligated to purchase such gas production at a purchase price per Mcf equal to the greater of the Index Price and the Floor price for gas produced in any quarter during the Primary Term, and at a purchase price per Mcf equal to the Index Price for gas produced in any quarter after the Primary Term.
Under a standby performance agreement Eastern American has agreed to make payments under the Gas Purchase Contract to the extent such payments are not made by Eastern Marketing. In addition Eastern Marketing's performance is secured by a standby Letter of Credit which originally was in the amount of $15 million, and declined to $12 million on June 30, 1996 and will decline annually thereafter to an amount equal to the lessor of (i) the remaining undrawn face amount thereof as of such date and (ii) $9 million in 1997, $6 million in 1998, and $3 million in 1999.
B-9
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
6. TREASURY OBLIGATIONS:
The Treasury Obligations are directly owned by the Unitholders and are not part of Trust Corpus. The Treasury Obligations are on deposit with the depository pursuant to the Deposit Agreement.
The high and low closing prices of the Treasury Obligations, which have a $1,000 face principal amount, as quoted in the over-the-counter market for United States Treasury Obligations are as follows:
HIGH LOW ------- ------- Quarter ended March 31, 1994 ................... $280.50 $241.50 Quarter ended June 30, 1994 .................... 244.70 223.80 Quarter ended September 30, 1994 ............... 240.31 218.44 Quarter ended December 31, 1994 ................ 238.34 212.91
Quarter ended March 31, 1995 ................... $254.91 $231.03 Quarter ended June 30, 1995 .................... 305.72 253.13 Quarter ended September 30, 1995 ............... 308.47 279.25 Quarter ended December 31, 1995 ................ 347.72 307.59
Quarter ended March 31, 1996 ................... $348.31 $301.75 Quarter ended June 30, 1996 .................... 309.65 286.72 Quarter ended September 30, 1996 ............... 311.25 291.25 Quarter ended December 31, 1996 ................ 345.43 312.30
On December 31, 1996, December 31, 1995 and December 31, 1994, the closing price of the Treasury Obligations, as quoted on such market, was $331.64, $347.72 and $232.91, respectively.
7. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED):
Information regarding estimates of the proved gas reserves attributable to the Trust are based on reports prepared by independent petroleum engineering consultants. Estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission. 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.
B-10
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
7. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED):
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. Fixed gas prices have been used during the Primary Term. The gas prices used thereafter are based on the average of October, November and December 1996 prices paid by Eastern Marketing.
The reserves and revenue values for the Underlying Properties transferred to the Trust were estimated from projections of reserves and revenue values attributable to the combined Eastern American and Trust interests in these properties. Reserve quantities are calculated differently for the Net Profits Interests because such interests do not entitle the Trust to a specific quantity of gas but to 90 percent of the Net Proceeds derived therefrom. Accordingly, there is no precise method of allocating estimates of the quantities of proved reserves between those held by the Trust and the interests to be retained by Eastern American. For purposes of this presentation the proved reserves attributable to the Net Profits Interests have been proportionately reduced to reflect the future estimated costs and expenses deducted in the calculation of Net Proceeds with respect to the Net Profits Interests. The reserves presented for the Net Profits Interests reflect quantities of gas that are free of future costs or expenses. The allocation of proved reserves between the Trust and Eastern American will vary in the future as relative estimates of future gross revenues and future costs and expenses vary.
The royalty portion of the Net Profits Interests was calculated beyond the liquidation date of the Trust (May 15, 2013), even though the terms of the Trust Agreement require that the Royalty Net Profits Interest will be sold by the Trustee on or about this date and a liquidating distribution from the sales proceeds from such sale would be made to the Unitholders. The Term Net Profits Interests was limited to the 20-year period as defined by the Trust Agreement.
B-11
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
7. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED), CONTINUED:
The following table reconciles the change in proved reserves attributable to the Trust's share of the Net Profits Interests ("NPI") January 1, 1994 to December 31, 1996:
Royalty Term Total NPI NPI NPI (MMCF) (MMCF) (MMCF) ------- ------- ------- Balance, January 1, 1994 ............. 31,132 32,101 63,233 Production ........................... (2,318) (2,162) (4,480) Revisions of previous estimates ...... (2,040) (1,661) (3,701) ------- ------- ------- Balance, December 31, 1994 ........... 26,774 28,278 55,052 Production ........................... (2,026) (2,006) (4,032) Revisions of previous estimates ...... 521 807 1,328 ------- ------- ------- Balance, December 31, 1995 ........... 25,269 27,079 52,348 Production ........................... (1,831) (2,197) (4,028) Revisions of previous estimates ...... (934) (4,010) (4,944) ------- ------- ------- Balance, December 31, 1996 ........... 22,504 20,872 43,376 ======= ======= =======
B-12
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued -----------
7. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED), CONTINUED:
Reserve quantities of proved developed gas reserves are as follows:
Royalty Term Total NPI NPI NPI (MMCF) (MMCF) (MMCF) ------ ------ ------ December 31, 1994 ........ 26,774 21,694 48,468 ====== ====== ====== December 31, 1995 ........ 25,269 21,579 46,848 ====== ====== ====== December 31, 1996 ........ 22,504 19,689 42,193 ====== ====== ======
B-13
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
7. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED), CONTINUED:
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
The following is the standardized measure of discounted future net cash flows as of December 31, 1996 (in thousands):
Royalty Term Total NPI NPI NPI ------- ------- -------- Future cash inflows ....................... $85,274 $71,472 $156,746 Future production taxes ................... 4,631 3,233 7,864 Future production costs ................... 13,742 5,610 19,352 ------- ------- -------- Future net inflows ........................ 66,901 62,629 129,530 10% discount factor .................... 38,086 27,843 65,929 ------- ------- -------- Standardized measure of discounted future net cash flows ................. $28,815 $34,786 $ 63,601 ======= ======= ========
The following is the standardized measure of discounted future net cash flows as of December 31, 1995 (in thousands): Royalty Term Total NPI NPI NPI ------- ------- -------- Future cash inflows ....................... $76,645 $75,482 $152,127 Future production taxes ................... 3,524 3,024 6,548 Future production costs ................... 12,769 5,926 18,695 ------- ------- --------
Future net inflows ........................ 60,352 66,532 126,884 10% discount factor ....................... 32,364 29,510 61,874 ------- ------- --------
Standardized measure of discounted future net cash flows ................. $27,988 $37,022 $ 65,010 ======= ======= ========
B-14
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
7. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED), CONTINUED:
The following is the standardized measure of discounted future net cash flows as of December 31, 1994 (in thousands): Royalty Term Total NPI NPI NPI ------- ------- -------- Future cash inflows ....................... $82,716 $81,929 $164,645 Future production taxes ................... 3,418 3,242 6,660 Future production costs ................... 12,688 6,224 18,912 ------- ------- -------- Future net inflows ........................ 66,610 72,463 139,073 10% discount factor ....................... 35,759 31,369 67,128 ------- ------- -------- Standardized measure of discounted future net cash flows ................. $30,851 $41,094 $ 71,945 ======= ======= ========
B-15
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
7. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED), CONTINUED:
Changes in Standardized Measure of Discounted Future Net Cash Flows:
The following schedule reconciles the changes during 1994, 1995 and 1996 in the standardized measure of discounted future net cash flows relating to proved reserves (in thousands):
Royalty Term Total NPI NPI NPI -------- -------- -------- Standardized measure, January 1, 1994 ...... $ 39,539 $ 48,952 $ 88,491
Net proceeds to the Trust .................. (5,328) (5,627) (10,955) Revisions of previous estimates ............ (2,665) (2,170) (4,835) Accretion of discount ...................... 3,954 4,895 8,849 Net change in variable price and production costs ........................ (4,649) (4,956) (9,605) -------- -------- -------- Standardized measure, December 31, 1994 .... 30,851 41,094 71,945 Net proceeds to the Trust .................. (4,629) (4,960) (9,589) Revisions of previous estimates ............ 647 1,002 1,649 Accretion of discount ...................... 3,085 4,109 7,194 Net change in price and production costs ... (2,895) (3,274) (6,169) Other ...................................... 929 (949) (20) -------- -------- -------- Standardized measure, December 31, 1995 .... 27,988 37,022 65,010 Net proceeds to the Trust .................. (5,615) (5,207) (10,822) Revisions of previous estimates ............ (1,369) (5,880) (7,249) Accretion of discount ...................... 2,799 3,702 6,501 Net change in price and production costs ... 5,050 4,683 9,733 Other ...................................... (38) 466 428 -------- -------- -------- Standardized measure, December 31, 1996 .... $ 28,815 $ 34,786 $ 63,601 ======== ======== ========
B-16
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO FINANCIAL STATEMENTS, Continued ----------
8. QUARTERLY FINANCIAL DATA (UNAUDITED):
The following is a summary of royalty income and distributable income declared per unit by quarter in 1994, 1995 and 1996 (in thousands):
1996 MAR.31 JUNE 30 SEPT 30 DEC. 31 TOTAL - ----------------------------- -------- -------- -------- -------- -------- Royalty income .............. $ 2.730 $ 3.129 $ 3.121 $ 3.123 $ 12.103 ======== ======== ======== ======== ======== Distributable income ........ $ 2.273 $ 2.713 $ 2.679 $ 2.722 $ 10.387 ======== ======== ======== ======== ======== Distributable income per unit $ .3852 $ .4598 $ .4541 $ .4615 $ 1.7606 -------- ======== ======== ======== ========
1995 MAR.31 JUNE 30 SEPT 30 DEC. 31 TOTAL - ----------------------------- -------- -------- -------- -------- -------- Royalty income ............... $ 2,709 $ 2,699 $ 2,625 $ 2,721 $10,754 ======= ======= ======= ======= ======= Distributable income ......... $ 2,272 $ 2,291 $ 2,241 $ 2,515 $ 9,319 ======= ======= ======= ======= ======= Distributable income per unit $ .3852 $ .3882 $ .3798 $ .4263 $1.5795 ------- ======= ======= ======= =======
1994 MAR.31 JUNE 30 SEPT 30 DEC. 31 TOTAL - ----------------------------- -------- -------- -------- -------- -------- Royalty income ............... $ 3,154 $ 3,237 $ 3,002 $ 2,801 $12,194 ======= ======= ======= ======= ======= Distributable income ......... $ 2,720 $ 2,807 $ 2,603 $ 2,618 $10,748 ======= ======= ======= ======= ======= Distributable income per unit $ .4610 $ .4758 $ .4412 $ .4437 $1.8217 ======= ======= ======= ======= =======
B-17