SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

(Mark One)

    

ý

QUARTERLY REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended June 30, 2002

 

OR

 

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                  to

 

 

Commission File Number 1-11748

 

 

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

 

 

PART I — FINANCIAL INFORMATION

 

             ITEM 1.   Financial Statements

 

EASTERN AMERICAN NATURAL GAS TRUST

 

STATEMENTS OF DISTRIBUTABLE INCOME

(Unaudited)

 

		Six Months Ended						Three Months Ended
		June 30						June 30
		2002			2001			2002			2001
Royalty Income		$	3,963,220		$	8,147,876		$	2,191,952		$	3,840,489
Operating Expenses:
Taxes on production and property		271,167			550,493			150,032			258,760
Operating cost charges		251,274			256,554			125,637			128,277
Total Operating Expenses		522,441			807,047			275,669			387,037
Net Proceeds to the Trust		3,440,779			7,340,829			1,916,283			3,453,452
General and Administrative Expenses		(320,465		)	(306,687		)	(155,015		)	(143,750		)
Interest Income		1,017			2,952			316			1,445
Cash Proceeds on Sale of Net Profits Interests		492,043			0			188,605			0
Distributable Income		$	3,613,374		$	7,037,094		$	1,950,189		$	3,311,147
Distributable Income Per Unit (5,900,000 units authorized and outstanding)		$	0.6124		$	1.1927		$	0.3305		$	0.5612

 

 

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

 

2

EASTERN AMERICAN NATURAL GAS TRUST

 

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

 

		June 20, 2002				December 31, 2001
		(Unaudited)
Assets:
Cash		$	316			$	1,201
Net Proceeds Receivable		2,104,888				1,957,988
Net Profits Interests in Gas Properties		93,162,180				93,162,180
Accumulated Amortization		(52,200,932			)	(49,992,199			)
Total Assets		$	43,066,452			$	45,129,170
Liabilities and Trust Corpus:
Trust General and Administrative Expenses Payable		$		155,015		$		172,034
Distributions Payable		1,950,189				1,787,155
Trust Corpus (5,900,000 Trust Units authorized and outstanding)		40,961,248				43,169,981
Total Liabilities and Trust Corpus		$	43,066,452			$	45,129,170

 

 

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

 

3

EASTERN AMERICAN NATURAL GAS TRUST

 

STATEMENT OF CHANGES IN TRUST CORPUS

(Unaudited)

 

		Six Months			Six Months
		Ended			Ended
		June 30, 2002			June 30, 2001
Trust Corpus, Beginning of Period		$	43,169,981		$	47,650,950
Distributable Income		3,613,373			(7,037,094		)
Distributions Payable to Unitholders		(3,613,373		)	7,037,094
Amortization of Net Profits Interests in Gas Properties		(2,208,733		)	(2,220,866		)
Trust Corpus, End of Period		$	40,961,248		$	45,430,084

 

 

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

 

 

4

 

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”).  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 in West Virginia and Pennsylvania (the “Underlying Properties”).  The Net Profits Interests consisted of a royalty interest in 322 wells and a term interest in the remaining wells and locations.  Prior to or on 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.

 

        Effective May 8, 2000, The Bank of New York acquired the corporate trust business of the Bank of Montreal Trust Company / Harris Trust.  Consequently, the Bank of New York serves as Trustee.

 

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 Unitholders; and the Trustee will make quarterly cash distributions to Unitholders from funds of the Trust.

 

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

 

5

 

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, 2001.

 

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 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 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.

 

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 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.

 

6

 

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

 

Cautionary Statement

 

        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, the Trust is unable 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 Trustee and Eastern American, disclaims 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 which 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”. The “Operating Cost Charge” for 2002 is based on an annual rate of $503,354, and for 2001 was an annual rate of $513,106. In subsequent years, the Operating Cost Charge will fluctuate based on the index of average weekly earnings of Crude Petroleum and Gas Production Workers (published

 

7

by the United States Department of Labor, Bureau of Labor Statistics), but not more than 5% per year.  The Operating Cost Charge was not increased as Development Wells were 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 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 Contracts 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.

 

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 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 June 30, 2002, an additional volume of 5,260 Mcf was delivered to the Trust, as compared to 5,833 Mcf for the quarter ended June 30, 2001.  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

 

8

are online and producing.  (See the Trust’s Form 10-K for the fiscal year ended December 31, 2001 for a more complete description of the Development Wells.)

 

During the quarter ended March 31, 2002, a Coal Lessee contacted Eastern American and inquired as to whether it would sell the Western Pocahontas # 7, # 8 and # 10 Wells which are wells in which the Trust owns a Net Profits Interest.

 

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 to determine if it could cause the Trust to sell its Net Profits Interest in the Wells.  Upon review, it was discovered that the Net Profits Interest associated with the Western Pocahontas # 7 well accounted for more than .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.

 

Subsequent thereto the Coal Lessee insisted that the well needed to be plugged in order for them to proceed with their proposed mining operations.  The Coal Lessee took the position that the coal estate was the dominate estate and, that under the applicable oil and gas lease and case law, that the Coal Lessee could cause the Trust and Eastern American to plug and abandon the well so long as the Coal Lessee fairly compensated the Trust and Eastern American.  Eastern American and the Trust did not necessarily agree with the Coal Lessee position, however the Coal Lessee threatened to institute a Declaratory Judgment Action to determine the respective interest of the parties.

 

As a result, 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 during the quarter ended March 31, 2002.  The Trust’s share of the proceeds of $303,438 was distributed to the Trust during the quarter ended March 31, 2002.

 

During the quarter ended June 30, 2002, the Coal Lessee purchased the two additional wells, the Western Pocahontas # 8 and #10, in which the Trust owns a net profits interest for the amount of $209,561.  The Trust’s share of the proceeds of $188,605 was included in the Distributed Income of the Trust during the quarter ended June 30, 2002.

 

 

9

 

Comparison of Results of Operations for Three Months Ended June 30, 2002 and Three Months Ended June 30, 2001

 

The Trust’s distributable income was $1,950,189 for the three months ended June 30, 2002 as compared to $3,311,147 for the three months ended June 30, 2001.  This decrease was due to a decrease in the price payable to the Trust under the Gas Purchase Contract as discussed below ($3.776 per Mcf for the three months ended June 30, 2002; $6.372 per Mcf for the three months ended June 30, 2001).  This decrease was also due to a decrease in production of gas attributable to the Net Profits Interests for the three months ended June 30, 2002 (582 Mmcf) as compared to the three months ended June 30, 2001 (604 Mmcf).  The decline in production is primarily attributable to natural production declines and the required plugging and abandonment of  wells.  Taxes on production and property were $150,032 for the three months ended June 30, 2002 as compared to $258,760 for the three months ended June 30, 2001.  This decrease was due to the decrease in Royalty Income for the three months ended June 30, 2002 ($2,191,952) as compared to the three months ended June 30, 2001 ($3,840,489).  The distributable income includes Cash Proceeds on Sale of Net Profits Interest of $188,605 for the quarter ended June 30, 2002, while no such sales were recognized in the corresponding prior quarter.

 

The price payable to the Trust for gas production attributable to the Net Profits Interests was $3.776 per Mcf for the three months ended June 30, 2002 and $6.372 per Mcf for the three months ended June 30, 2001.  The price per Mcf was lower for the three months ended June 30, 2002 than for the corresponding three month period ended June 30, 2001 due to a decrease in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($3.133 per Dth for the three months ended June 30, 2002; $5.493 per Dth for the three months ended June 30, 2001).

 

Comparison of Results of Operations for Six Months Ended June 30, 2002 and Six Months Ended June 30, 2001

 

The Trust’s distributable income was $3,613,374 for the six months ended June 30, 2002 as compared to $7,037,094 for the six months ended June 30, 2001.  This decrease was due to a decrease in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($3.409 per Mcf for the six months ended June 30, 2002; $6.594 per Mcf for the six months ended June 30, 2001).  This decrease was also due to a decrease in production of gas attributable to the Net Profits Interests for the six months ended June 30, 2002 (1,164 Mmcf) as compared to the six months ended June 30, 2001 (1,234 Mmcf).  The decline in production is primarily attributable to natural production declines and the required plugging and abandonment of wells.  Taxes on production and property were $271,167 for the six months ended June 30, 2002 as compared to $550,493 for the six months ended June 30, 2001.  This decrease was due to the decrease in Royalty Income for the six months ended June 30, 2002 ($3,963,220) as compared to the six months ended June 30, 2001 ($8,147,876).  The distributable income includes Cash Proceeds on Sale of Net Profits Interest of $492,043 for the six months ended June 30, 2002, while no such sales were recognized in the corresponding prior quarter.

 

10

 

The average price payable to the Trust for gas production attributable to the Net Profits Interests was $3.409 per Mcf for the six months ended June 30, 2002 and $6.594 per Mcf for the six months ended June 30, 2001.  The average price per Mcf was lower for the six months ended June 30, 2002 than for the corresponding six month period ended June 30, 2001 due to a decrease in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($2.799 per Dth for the six months ended June 30, 2002; $5.695 per Dth for the six months ended June 30, 2001).

 

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 June 30, 2002, 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 $566.40 and $518.10 respectively.  On June 30, 2002 the closing price of the Treasury Obligations, as quoted on such market, was $561.30.

 

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 June 30, 2002, this option was exercised on 7,900 Trust Units.  (See the Trust’s 10-K for the fiscal year ended December 31, 2001 for a more complete description of the Withdrawal of Trust Units and Restriction on Transfer.)

 

11

 

ITEM 6.	Exhibits and Reports on Form 8-K.
	(a)	Exhibits
		None
	(b)	Reports on Form 8-K
		No reports on Form 8-K were filed during the fiscal quarter ended June 30, 2002.

 

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:  Bank of New York, Trustee
	/s/ Cassandra Shedd
	Cassandra Shedd
	Assistant Vice President
	Bank of New York
	Title:  Agent

 

Date: August 14, 2002

 

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.

 

The Registrant also has no chief executive officer or chief financial officer, and therefore this periodic report is not accompanied by a written statement of any such person pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

12