UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

EASTERN AMERICAN NATURAL GAS TRUST

(Exact name of registrant as specified in its charter)

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes   ý           No   o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Yes   ý           No   o

 

As of November 12, 2003, 5,900,000 Units of Beneficial Interest in Eastern American Natural Gas Trust were outstanding.

 

 

PART I – FINANCIAL INFORMATION

ITEM 1.   Financial Statements

 

EASTERN AMERICAN NATURAL GAS TRUST

STATEMENTS OF DISTRIBUTABLE INCOME

(Unaudited)

 

		Nine Months Ended September 30						Three Months Ended September 30
		2003			2002			2003			2002
Royalty Income		$	10,165,525		$	6,412,497		$	3,521,454		$	2,449,277
Operating Expenses
Taxes on production and property		692,070			436,647			239,370			165,480
Operating cost charges		382,627			376,506			127,405			125,232
Total Operating Expenses		1,074,697			813,153			366,775			290,712
Net Proceeds to the Trust		9,090,828			5,599,344			3,154,679			2,158,565
General and Administrative Expenses		(671,255		)	(449,823		)	(140,679		)	(129,358		)
Interest Income		748			1,404			259			387
Cash Proceeds on Sale of Net Profits Interests		10,293			492,043			0			0
Distributable Income		8,430,614			5,642,968			3,014,259			2,029,594
Cash Reserve		(115,000		)	0			0			0
Distribution Amount		$	8,315,614		$	5,642,968		$	3,014,259		$	2,029,594
Distributable Income Per Unit (5,900,000 units authorized and outstanding)		$	1.4289		$	0.9564		$	0.5109		$	0.3440
Distribution Amount Per Unit (5,900,000 units authorized and outstanding)		$	1.4094		$	0.9564		$	0.5109		$	0.3440

 

The accompanying notes are an integral part of these financial statements.

 

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EASTERN AMERICAN NATURAL GAS TRUST

 

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

 

		September 30, 2003			December 31, 2002
		(Unaudited)
Assets:
Cash		$	50,927		$	406
Net Proceeds Receivable		3,154,679			2,310,449
Net Profits Interests in Gas Properties		93,162,180			93,162,180
Accumulated Amortization		(57,532,379		)	(54,466,381		)
Total Assets		$	38,835,407		$	41,006,654
Liabilities and Trust Corpus:
Trust General and Administrative Expenses Payable		$	76,347		$	145,098
Distributions Payable		3,014,259			2,165,757
Trust Corpus (5,900,000 Trust Units authorized and outstanding)		35,744,801			38,695,799
Total Liabilities and Trust Corpus		$	38,835,407		$	41,006,654

 

The accompanying notes are an integral part of these financial statements.

 

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EASTERN AMERICAN NATURAL GAS TRUST

 

STATEMENT OF CHANGES IN TRUST CORPUS

(Unaudited)

 

		Nine Months Ended September 30, 2003			Nine Months Ended September 30, 2002
Trust Corpus, Beginning of Period		$	38,695,799		$	43,169,981
Distributable Income		8,430,614			5,642,968
Distributions Payable to Unitholders		(8,315,614		)	(5,642,968		)
Amortization of Net Profits Interests in Gas Properties		(3,065,998		)	(3,363,418		)
Trust Corpus, End of Period		$	35,744,801		$	39,806,563

 

The accompanying notes are an integral part of these financial statements.

 

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EASTERN AMERICAN NATURAL GAS TRUST

 

NOTES TO UNAUDITED FINANCIAL STATEMENTS

 

NOTE 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 (“Trustee”), and Wilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”).  Effective May 8, 2000, The Bank of New York acquired the corporate trust business of the then current Trustee and consequently is currently serving as 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 (the “Development Wells”) in West Virginia and Pennsylvania (the “Underlying Properties”).

 

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.  The financial statements of the Trust to which these notes relate do not incorporate information concerning the Treasury Obligations, the beneficial interest in which is held for the Unitholders by the Depositary.

 

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 that is contingent, uncertain in amount or 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.

 

After the Trust was formed, 59 of the 65 Development Wells were drilled and completed. The remaining six Development Wells were not drilled. Clear title to two of the Development Wells could not be established, and they were excluded from the Trust in accordance with the conveyance transferring them to the Trust. Eastern American asserted the remaining four undrilled Development Wells, if drilled, would be too close to then existing wells on the property or an adjoining property, and thereafter settled its dispute with the Trust about drilling those four Development Wells by agreeing instead to pay the Trust annually for the annual volume of gas projected to be produced from those Development Wells as if they had been drilled.

 

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The Net Profits Interests initially consisted of a royalty interest (“Royalty NPI”) in 322 wells and a term interest (“Term NPI”) in the remaining wells and locations. As of September 30, 2003, the Trust held Net Profits Interests in 677 wells, consisting of Royalty NPI in 317 wells and Term NPI in the remaining wells. The Term NPI expire by their terms on May 15, 2013, or such earlier time as 41,683 MMcf of gas has been produced that is attributable to Eastern American’s net revenue interest in the properties burdened by the Term NPI. As of December 31, 2002, based on the Independent Petroleum Engineer’s Report, 18,319 MMcf of the maximum 41,683 MMcf has been produced.

 

Between May 15, 2012, and May 15, 2013 (the “Liquidation Date”), the Trustee is required to sell all the Royalty NPI and liquidate the Trust. Under the Trust Agreement, Eastern American has the right of first refusal to purchase any of the Royalty NPI the Trustee is required to sell after the Liquidation Date. If it exercises this right, Eastern American must pay the appraised Fair Value (as defined in the Trust Agreement) of the Royalty NPI, or the relevant third party offer price if a third party has offered to purchase the Royalty NPI. Unitholders of record on the relevant record dates will receive the net proceeds from selling the Royalty NPI in accordance with the Trust Agreement, and also will receive their respective share of the matured face amount of the Treasury Obligations held by the Depositary.

 

NOTE 2.  Basis of Presentation

 

The information furnished is based upon certain estimates of production for the periods presented and is therefore subject to adjustment in future periods to reflect actual production for the periods presented.  The information furnished reflects all adjustments which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim periods presented.  The accompanying financial statements are unaudited interim financial statements, and should be read in conjunction with the audited financial statements and notes thereto included in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2002.

 

NOTE 3.  Trust Accounting Policies

 

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 Unitholders.  Thus, the Statements of Distributable Income show Distributable Income, defined as Trust income available for distribution to Unitholders subject to Trustees Cash Reserves described in Part I, Item 2 before application of those Unitholders’ additional expenses, if any, for depletion, interest expense, and income taxes.  The Trust uses the accrual basis to recognize revenue, with Royalty Income recognized as reserves are extracted from properties and sold.  Expenses are also presented on an accrual basis.  Actual cash receipts will vary from the accrual of revenues due to, among other reasons, the payment provisions of the gas purchase contract between the Trust and Eastern Marketing Corporation  (a subsidiary of Eastern American), which requires

 

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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.

 

The Net Profits Interests are assessed annually 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 the extent that the net capitalized costs exceed the discounted future net revenues attributable to proved gas reserves of the Underlying Properties.   Any such writedown would not reduce distributable income, although it would reduce 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.

 

NOTE 4. Income Taxes

 

The Trust is a grantor trust and is not required to pay federal or state income taxes.  Accordingly, no provision for federal or state income taxes has been made.  All income is taxed to the Unitholders of the Trust.

 

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ITEM 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Cautionary Statement

 

The Trust, the Trustee and Eastern American, its officers or its agents on behalf of the Trust may, from time to time, make forward-looking statements (other than statements of historical fact).  When used herein, the words “anticipates,” “expects,” “believes,” “intends” or “projects” and similar expressions are intended to identify forward-looking statements.  To the extent that any forward-looking statements are made, neither the Trust, the Trustee or Eastern American is able to predict future changes in gas prices, gas production levels, economic activity, legislation and regulation, and certain changes in expenses of the Trust.  In addition, the Trust’s future results of operations and other forward looking statements contained in this item and elsewhere in this report involve a number of risks and uncertainties.  As a result of variations in such factors, actual results may differ materially from any forward-looking statements.  Some of these factors are described below.  The Trust, the Trustee and Eastern American disclaim any obligations to update forward looking statements and all such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph and by the statements in the Annual Report on Form 10-K.

 

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 the cash proceeds to Unitholders which the Trust receives in respect of the Net Profits Interests (net of Trust expenses), and to perform certain administrative functions in respect of the Net Profits Interests and the Depositary Units.  Accordingly, the Trust derives substantially all of its income and cash flows from the Net Profits Interests.  The Trust has no source of liquidity or capital resources other than the cash flows from the Net Profits Interests.

 

The Net Profits Interests were created pursuant to conveyances (the “Conveyances”) from Eastern American to the Trust.  In connection therewith, Eastern American assigned its rights under a gas purchase contract (the “Gas Purchase Contract”) which obligates Eastern Marketing Corporation, a subsidiary of Eastern American, to purchase all of the natural gas produced from the Underlying Properties that is attributable to the Net Profits Interests.

 

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” for such quarter, multiplied by (b) the applicable price for such quarter under the Gas Purchase Contract.  “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”.

 

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The “Operating Cost Charge” for 2003 is based on an annual rate of $510,444, and for 2002 was an annual rate of $503,354. The increase in the 2003 “Operating Cost Charge” reflects a prospective adjustment made based upon changes in the Crude Petroleum and Gas Production Workers Index for 2002.  As provided in the Conveyances, the Operating Cost Charge will fluctuate based on the lesser of (A) five percent (5%) or (B) a percentage, not less than zero percent (0%), equal to the percentage increase, if any, in the average weekly earnings of Crude Petroleum and Gas Production Workers for the last calendar year, as shown by the index of average weekly earnings of Crude Petroleum and Gas Production Workers, as published by the United States Department of Labor, Bureau of Labor Statistics, based on December-to-December comparison.  The Crude Petroleum and Gas Production Workers Index for 2003 decreased by 3.1%.  The Operating Cost Charge was not increased as Development Wells were completed but is 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 the Trust’s interest in the Underlying Properties, or production therefrom.

 

Pursuant to the Gas Purchase Contract, Eastern Marketing is obligated to purchase such gas production at a purchase price per Mcf equal to the Index Price.  The Index Price for any quarter is determined solely by reference to the Variable Price component.  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 price 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 price 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 that is traded on the New York Mercantile Exchange.

 

Accordingly, the Index Price payable to the Trust for production may be higher or lower based on the fluctuations in natural gas futures prices during the relevant calculation period.  The price payable to the Trust will have a direct impact, positively or negatively, on the quarterly distributions payable by the Trust to its unit holders.

 

Eastern American had a disagreement with the Trust over Eastern American’s obligation to drill certain Development Wells that were closely offset by third parties.  The Trust agreed that in lieu of drilling these closely offset Development Wells that Eastern American could provide the Trust, on an annual basis commencing on April 1, 1997, and over the remaining life of the Trust, a volume of gas

 

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which is equal to the projected volumes of the wells as if they had been drilled.  These volumes have been estimated by Ryder Scott Company, independent petroleum engineers.  During the quarter ended September 30, 2003, an additional volume of 4,822 Mcf was delivered to the Trust, as compared to 5,260 Mcf for the quarter ended September 30, 2002.  These additional volumes fulfill Eastern American’s obligation to provide volumes for Development Wells that had been closely offset by third parties.

 

Eastern American has fulfilled its obligation with respect to the drilling of the Development Wells. Since the inception of the Trust, Eastern has drilled a total of 59 Development Wells, which are online and producing.  (See the Trust’s Form 10-K for the fiscal year ended December 31, 2002 for a more complete description of the Development Wells.)

 

During 2002, Eastern American was asked to sell 3 wells in which the Trust owned a Net Profits Interest (the Western Pocahontas #7, #8 and #10 wells).  The party seeking to purchase the wells owned the right to mine for coal on such properties (the “Coal Lessee”).  The Coal Lessee stated that the wells would materially interfere with the Coal Lessee’s proposed mining operations.

 

Eastern American reviewed the Trust Agreement and production from these wells, and determined that the Net Profits Interest associated with the Western Pocahontas # 7 well accounted for more than 0.25% of the total production from the Underlying Properties for the prior twelve (12) month period.  Eastern American advised the Coal Lessee that it could not sell this well.

 

Subsequently, the Coal Lessee asserted that the coal estate in the relevant Underlying Properties was the dominate estate and that under the relevant oil and gas leases and applicable case law, the Coal Lessee could cause the Trust and Eastern American to plug and abandon the well.  Eastern American and the Trust did not necessarily agree with the Coal Lessee position, however, and in an effort to avoid litigation, the Trust and Eastern American entered into a Settlement Agreement and Release of All Claims with the Coal Lessee pursuant to which Eastern agreed to sell the Western Pocahontas # 7 well for the amount of $426,187.  The Trust’s share of the proceeds of $303,438 was included in Distributable Income to the Trust during the quarter ended March 31, 2002.  The Coal Lessee purchased the two additional wells, the Western Pocahontas # 8 and #10 for the amount of $209,561.  The Trust’s share of the proceeds of $188,605 was also included in the Distributable Income of the Trust during the quarter ended June 30, 2002.

 

During the quarter ended March 31, 2003, a Coal Lessee contacted Eastern American and inquired as to whether it would sell the U.S. Steel Well # 26, which is a well in which the Trust owns a Net Profits Interests.  The Coal Lessee stated that the well would materially interfere with the Coal Lessee’s proposed mining operations.  Eastern American reviewed the Trust Agreement and production from this well to determine if it could cause the Trust to sell its Net Profits Interest in the well.  Upon review, it was discovered that the Net Profits Interests associated with the U.S. Steel #26 well accounted for less than 0.25% of the total production from the Underlying Properties for the prior twelve (12) month period.  Eastern American advised the Coal Lessee that it could sell this well.  Eastern American received $11,437 for the sale of the U.S Steel Well #26.  The effective date of the sale was March 1, 2003.  However, the transaction did not close until April 17, 2003.

 

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Therefore, the Trust’s share of the proceeds of $10,293 was included in the Distributable Income of the Trust during the quarter ending June 30, 2003 as well as the nine months ended September 30, 2003.

 

Over the remaining life of the Trust, additional wells may need to be disposed of for similar reasons.

 

Comparison of Results of Operations for Three Months Ended September 30, 2003 and Three Months Ended September 30, 2002

 

The Trust’s distributable income was $3,014,259 for the three months ended September 30, 2003 as compared to $2,029,594 for the three months ended September 30, 2002.  This increase was due to an increase in Royalty Income for the three months ended September 30, 2003 ($3,521,454) as compared to the three months ended September 30, 2002 ($2,449,277).  The increase in Royalty Income was due to an increase in the price payable to the Trust under the Gas Purchase Contract as discussed below ($6.381 per Mcf for the three months ended September 30, 2003; $4.028 per Mcf for the three months ended September 30, 2002).  This increase was offset by a decrease in production of gas attributable to the Net Profits Interests for the three months ended September 30, 2003 (552 Mmcf) as compared to the three months ended September 30, 2002 (608 Mmcf).  The decline in production is primarily attributable to natural production declines and the sale of a well.  Taxes on production and property were $239,370 for the three months ended September 30, 2003 as compared to $165,480 for the three months ended September 30, 2002.  The increase in taxes is due directly to the increase in Royalty Income as discussed above.

 

The price payable to the Trust for gas production attributable to the Net Profits Interests was $6.381 per Mcf for the three months ended September 30, 2003 and $4.028 per Mcf for the three months ended September 30, 2002.  The price per Mcf was higher for the three months ended September 30, 2003 than for the corresponding three month period ended September 30, 2002 due to an increase in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($5.501 per Dth for the three months ended September 30, 2003; $3.362 per Dth for the three months ended September 30, 2002).

 

Comparison of Results of Operations for Nine Months Ended September 30, 2003 and Nine Months Ended September 30, 2002

 

The Trust’s distributable income was $8,430,614 for the nine months ended September 30, 2003 as compared to $5,642,968 for the nine months ended September 30, 2002.  This increase was due to an increase in Royalty Income for the nine months ended September 30, 2003 ($10,165,525) as compared to the nine months ended September 30, 2002 ($6,412,497).  The increase in Royalty Income was due to an increase in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($6.207 per Mcf for the nine months ended September 30, 2003; $3.615 per Mcf for the nine months ended September 30, 2002).  This increase was offset by a decrease in production of gas attributable to the Net Profits Interests for the nine months ended September 30, 2003 (1,635 Mmcf) as compared to the nine months ended September 30, 2002 (1,772 Mmcf).  The

 

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decline in production is primarily attributable to natural production declines and the sale of wells.  Taxes on production and property were $692,070 for the nine months ended September 30, 2003 as compared to $436,647 for the nine months ended September 30, 2002.  The increase in taxes is due directly to the increase in Royalty Income as discussed above. Trust general and administrative expenses were $671,255 for the nine months ended September 30, 2003 as compared to $449,823 for the nine months ended September 30, 2002.  The increase in general and administrative fees was due primarily to an increase in legal fees of $197,114 (attributable primarily to determining the legal obligations of the Trust under the Sarbanes-Oxley Act of 2002 with respect to the public reports filed on behalf of the Trust) and increased fees for tax and audit services received of $15,242.  The distributable income includes Cash Proceeds on Sale of Net Profits Interests of $10,293 for the period ended September 30, 2003, while $492,043 was recognized in the corresponding prior nine months.

 

During the nine months ended September 30, 2003, the Trustee established a cash reserve in the amount of $115,000 to facilitate the payment of vendor invoices on a timely basis. No such reserve existed in the prior nine months ended September 30, 2002.  Establishing this reserve, reduced distributions payable by $115,000 or $0.0195 per unit for the nine months ended September 30, 2003. Amortization of Nets Profits Interests in Gas Properties was $3,065,998 for the nine months ended September 30, 2003 as compared to $3,363,418 for the nine months ended September 30, 2002.  This decrease was primarily due to the decrease in production volumes.

 

The average price payable to the Trust for gas production attributable to the Net Profits Interests was $6.207 per Mcf for the nine months ended September 30, 2003 and $3.615 per Mcf for the nine months ended September 30, 2002.  The price per Mcf was higher for the nine months ended September 30, 2003 than for the corresponding nine month period ended September 30, 2002 due to an increase in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($5.342 per Dth for the nine months ended September 30, 2003; $2.987 per Dth for the nine months ended September 30, 2002).

 

ITEM 3.  Quantitative and Qualitative Disclosures about Market Risk

 

The Trust does not engage in any operations, and does not utilize market risk sensitive instruments, either for trading purposes or for other than trading purposes.  As described elsewhere herein, the Depositary Units consist of beneficial ownership of one unit of beneficial interest in the Trust and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon Treasury Obligation maturing on May 15, 2013.  High and low price information for the Treasury Obligations is included under Part II Item 5.  As described elsewhere herein, gas production attributable to the Net Profits Interest is sold to a wholly owned subsidiary of Eastern American pursuant to the Gas Purchase Contract described herein.

 

ITEM 4.  Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures.  The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports

 

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that it files or submits under the Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and regulations.  Disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Trust is accumulated and communicated by the working interest owner, Eastern American Energy Corporation (“Eastern American”), to The Bank of New York, as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.

 

As of September 30, 2003, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures.  Mauro Palladino, a Vice President of the Trustee, has concluded that the controls and procedures are effective at the reasonable assurance level, while noting certain limitations on disclosure controls and procedures as set forth below.

 

Due to the contractual arrangements of (i) the Trust Agreement, and (ii) the rights of the Trustee under the Conveyances regarding information furnished by Eastern American, there are certain potential weaknesses that may limit the effectiveness of disclosure controls and procedures established by the Trustee or its employees and their ability to verify the accuracy of certain financial information.  The contractual limitations creating potential weaknesses in disclosure controls and procedures may be deemed to include:

 

•                  Eastern American and its consolidated subsidiaries manage (i) historical operating data, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, the effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures and (iii) geological data relating to reserves.  While the Trustee requests material information for use in periodic reports as part of its disclosure controls and procedures, the Trustee does not manage this information, and relies entirely on Eastern American to provide accurate and timely information when requested for use in the Trust’s reports.

 

•                  Under the terms of the Trust Agreement, the Trustee is entitled to, and in fact does rely, upon certain experts in good faith, including (i) the independent reserve engineer with respect to the annual reserve report, which includes projected production, operating expenses and capital expenses, and (ii) the independent auditors the Trustee has contracted with respect to the annual audit and quarterly reviews of financial data provided by Eastern American.  Other than contracting independent auditors and reviewing the financial and other information provided to the Trust by Eastern American on a quarterly basis, the Trustee makes no independent or direct verification of this financial or other information. While the Trustee has no reason to believe its reliance upon experts is unreasonable, this reliance on experts and restricted access to information may be viewed as a weakness.

 

The Trustee does not intend to expand its responsibilities beyond those permitted or required by the Trust Agreement and those required under applicable law.

 

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Changes in Internal Controls.  To the knowledge of the Trustee, there have been no significant changes in the Trust’s internal controls that could significantly affect the Trust’s internal controls subsequent to the date the Trustee completed its evaluation.  The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal controls of Eastern American.

 

PART II – OTHER INFORMATION

 

ITEM 1.	Legal Proceedings.
		None.
ITEM 2.	Changes in Securities.
		None.
ITEM 3.	Defaults Upon Senior Securities.
		None.
ITEM 4.	Submission of Matters to a Vote of Security Holders.
		None.
ITEM 5.	Other Information.

 

For the calendar quarter ended September 30, 2003, the high and low closing prices of the Treasury Obligations (which have $1,000 face principal amount), as quoted in the over-the-counter market for United States Treasury obligations were $684.00 and $620.30 respectively.  On September 30, 2003 the closing price of the Treasury Obligations, as quoted on such market, was $663.90.

 

The Trust provides Unitholders with the option to separate the related Treasury Obligation from the Trust Units.  Upon exercising this option, the Trustee transfers such Trust Units from the name of the Depositary to the name of the withdrawing Unitholder.  As of September 30, 2003, this option was exercised on 77,900 Trust Units.  (See the Trust’s 10-K for the fiscal year ended December 31, 2002 for a more complete description of the Withdrawal of Trust Units and Restriction on Transfer.)

 

The Bank of New York has given notice of its intention to resign as Trustee and Depositary for the Eastern American Natural Gas Trust in accordance with (1) the Second Amended and Restated Trust Agreement of Eastern American Natural Gas Trust pursuant to which the Eastern American Natural Gas Trust was formed (the “Trust Agreement”) and (2) the Depositary Agreement (the “Depositary Agreement”) under which Trust Units and Treasury Obligations (as defined in the Trust Agreement) are held for Trust Unitholders. In accordance with the Trust Agreement and the

 

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Depositary Agreement, such resignations will not take effect until Trust Unitholders have approved a successor Trustee and Depositary.  Recommendations for a successor Trustee and Depositary will be made to the Trust Unitholders and voted upon at a meeting of the Trust Unitholders that will be scheduled in accordance with the Trust Agreement and the Depositary Agreement.

 

ITEM 6.   Exhibits and Reports on Form 8-K.

(a)                                 Exhibits

 

Exhibit Number		Description
3.1*		Second Amended and Restated Trust Agreement of Eastern American Natural Gas Trust
4.1*		Specimen Depositary Receipt
4.2*		Form of NPI Royalty Deposit Agreement
10.1*		Form of Conveyance
10.2*		Form of Term NPI Conveyance
10.3*		Form of Gas Purchase Contact between Eastern American Energy Corporation, Eastern Marketing Corporation and Eastern American Natural Gas Trust
10.5*		Form of Conveyance of Production Payment/Assignment of Production from Eastern American Natural Gas Trust to Eastern Marketing Corporation
10.6*		Form of Assignment and Standby Performance Agreement
31.		Rule 13a-14(a)/15d-14(a) Certification
32.		Section 1350 Certification
			(b)      Reports on Form 8-K
				No reports on Form 8-K were filed during the fiscal quarter ended September 30, 2003.

 

*   Incorporated 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 3.1, which is incorporated by reference to the Registrant’s Annual report on Form 10-K for the year ended December 31, 1994.

 

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SIGNATURES

 

Pursuant to the requirements 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.

 

	EASTERN AMERICAN NATURAL GAS TRUST
	By:  The Bank of New York, Trustee
	/s/  Mauro Palladino
	Name:  Mauro Palladino
	Title:    Vice President
	The Bank of New York

 

Date: November 12, 2003

 

The Registrant, Eastern American Natural Gas Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions.  Accordingly no additional signatures are available and none have been provided.

 

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