UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 1O-K
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
OR
|_| 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)
Delaware 36-7034603
(State or other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
The Bank of New York
Care of BNY Midwest Trust Company
2 North LaSalle Street, Suite 1020
Chicago, Illinois 60602
(Address of principal executive office) (Zip Code)
(312) 827-8553
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class On Which Registered
------------------- -------------------
Units of Beneficial Interest New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
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 |X| No |_|
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. |X|
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes |X| No |_|
As of March 15, 2003, 5,900,000 Units of Beneficial Interest in Eastern
American Natural Gas Trust have been issued, remain outstanding and are held by
non-affiliates of the registrant (the "Outstanding Units"). Of the Outstanding
Units, 107,900 Units of Beneficial Interest have been withdrawn from trading by
voluntary action of Holders and may not be traded unless such Holders comply
with certain requirements provided in the related Trust Agreement (the
"Withdrawn Units").
The aggregate market value of the Outstanding Units minus the Withdrawn
Units at the closing sales price on March 14, 2003 of $19.15 was approximately
$113 million.
Documents Incorporated By Reference: None
TABLE OF CONTENTS
PART I
Item 1. Business ........................................................1
Description of the Trust ........................................1
The Net Profits Interests .......................................2
The Underlying Properties .......................................6
Competition and Markets .........................................8
Regulation of Natural Gas .......................................8
Health, Safety and Environmental Regulation .................... 8
Description of Trust Units and Depositary Units .................9
Federal Income Tax Matters .....................................11
State Tax Considerations .......................................17
Available Information ..........................................18
Item 2. Properties .....................................................18
Item 3. Legal Proceedings ..............................................18
Item 4. Submission of Matters to a Vote of Unitholders .................18
PART II
Item 5. Market for the Registrant's Common Equity
and Related Matters ..................................... 19
Item 6. Selected Financial Data ........................................19
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations ......................20
Item 7A. Quantitative and Qualitative Disclosure About Market Risk ......22
Item 8. Financial Statements and Supplementary Data ....................22
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ......................22
PART III
Item 10. Directors and Executive Officers of the Registrant .............23
Item 11. Executive Compensation .........................................23
Item 12. Security Ownership of Certain Beneficial Owners
and Management ...........................................23
Item 13. Certain Relationships and Related Transactions .................23
Item 14. Controls and Procedures ........................................23
PART IV
Item 15. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K ......................................23
SIGNATURES ..................................................................25
CERTIFICATION ...............................................................25
PART I
Item 1. Business
DESCRIPTION OF THE TRUST
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,
"Btu" means British thermal units and "MMBtu" means million British thermal
units.
Cautionary Statement
The Trustee, its officers or its agents on behalf of the Trustee may, from
time to time, make forward-looking statements (other than statements of
historical fact). In addition, this Report on Form 10-K may contain
forward-looking statements. 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 Trustee 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 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.
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 was intended to be eligible for
credits ("Section 29 Credits") under the Internal Revenue Code of 1986 for
production of gas from Devonian shale or tight formations. The Net Profits
Interests to be acquired consisted of a royalty interest in 322 wells and a term
interest in the remaining wells and locations. Eastern American was obligated to
drill and complete, at its expense, 65 development wells (the "Development
Wells") on the development well locations conveyed to the Trust. Eastern
American has fulfilled its obligation with respect to the drilling of the
Development Wells (see Note 1 of Financial Statements attached as Annex B).
After May 15, 2012 and prior to or on May 15, 2013 (the "Liquidation Date"), the
Trustee is required to sell the remaining 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. Holders of Depositary Units
may withdraw the Treasury Obligations associated with the Trust Units see
"Description of Trust Units and Depositary Units". 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.
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 Underlying Properties (defined
below) 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 Trust is responsible for paying the Trustee's Fee and 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 fees paid to the Trustee for 2002 were $45,000. The total of all Trustee
fees and Trust administrative expenses for 2002 was $308,713. Such costs could
fluctuate in the future depending primarily on the expenses the Trust incurs for
professional services, particularly legal, accounting and engineering services.
In addition to such expenses, in 2002, the Trust paid Eastern American an
overhead reimbursement of $286,208, 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 Trust by Eastern American.
THE NET PROFITS INTERESTS
The Conveyances
The Net Profits Interests ("NPI") 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 or amount. Under the Trust
Agreement, the Trustee is directed to sell all remaining Royalty NPI after May
15, 2012 and prior to May 15, 2013, and net proceeds from selling such Royalty
NPI 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, 2002, 18,319 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 is not 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" (as defined in the Conveyances). The Operating Cost Charge
for 2002 was $501,738, for 2001 was $513,107 and for 2000 was $488,672. In 2003
and subsequent years, the Operating Cost Charge will fluctuate based on changes
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 will not increase more than 5% per year. The Operating Cost
Charge will be reduced for each well that is sold (free of the Net Profits
Interests) or plugged and abandoned. Capital Costs are defined as Eastern
American's working interest share of capital costs for operations on the
Underlying Properties having a useful life of at least three years, and
excluding any capital costs incurred in drilling the Development Wells. Taxes
refer to 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 from future distributions 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.
Under the Gas Purchase Contract, through the Primary Term ending December
31, 1999, Eastern Marketing purchased gas from the Trust at an Index Price
calculated based on a Fixed Price component (escalating at 5% a year and
carrying a 66-2/3% weighting) and a Variable Price component (varying with the
Henry Hub market price as described below and carrying a 33-1/3% weighting),
subject to a minimum Floor Price (as defined in the Gas Purchase Contract).
Since January 1, 2000, and the end of the Primary Term, Eastern Marketing has
purchased gas from the Trust at an Index Price composed only of the Variable
Price component, and not subject to any minimum Floor Price. 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.
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 by reference to materials previously filed with the Securities and
Exchange Commission. See Part IV, Item 15, "Exhibits, Financial Statement
Schedules, and Reports on Form 8-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.
Performance Support for Gas Purchase Contract
Gas production attributable to the Net Profits Interests will be purchased
by Eastern Marketing pursuant to the Gas Purchase Contract, which expires upon
the Liquidation Date of the Trust. Eastern American has agreed to make payment
under a standby performance agreement to the extent such payments are not made
by Eastern Marketing under the Gas Purchase Contract.
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 (i) the cash that the Trust receives on or before the tenth
day of the third month after the end of each calendar quarter ending before the
Trust is dissolved and that is attributable to production from the Net Profits
Interest held by the Trust during that calendar quarter, plus, with certain
exceptions, any other cash receipts of the Trust during such quarter, over (ii)
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 2002 were $0.28,
$0.33, $0.34, and $0.37 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.
Thus, a Unitholder's taxable income for a taxable year may differ from the cash
the Unitholder receives during that year. In addition, 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 Matters."
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 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 is 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.
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 accounting 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 (5) 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, 2002, such properties consisted of
678 producing gas wells. 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, 2002, proved
developed reserves attributable to the Net Profits Interests (reflecting
quantities of gas free of future costs and expenses based on estimated prices)
were approximately 20,634 MMcf. (See "Reserves").
The Appalachian Basin is a mature producing region with well known geologic
characteristics. Substantially all of the wells comprising 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. Eastern
American was obligated to bear the costs of drilling and completing the
Development Wells. Eastern American has fulfilled its obligation with respect to
the drilling of the Development Wells. (see Note 1 of Financial Statements
attached as Annex B)
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, 2002, 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, 2002 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% in accordance
with existing securities law requirements. A copy of the Reserve Report is
included as Exhibit A hereto.
Proved Gas Reserves
--------------------------------
(MMcf) Discounted
Estimated Estimated
Future Net Future Net
Developed Undeveloped Total Revenues(2) Revenues(2)
--------- ----------- -------- ----------- -----------
(Dollars in thousands)
Underlying Properties(1) 40,904 0 40,904 $143,931 $ 59,963
======== ======== ======== ======== ========
Net Profits Interests:
Royalty NPI ........ 12,025 0 12,025 $ 53,743 $ 22,953
Term NPI ........... 8,609 0 8,609 38,472 25,358
-------- -------- -------- -------- --------
Total ......... 20,634 0 20,634 $ 92,215 $ 48,311
======== ======== ======== ======== ========
----------
(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) 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.
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, if any. 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.
COMPETITION AND MARKETS
All of the production attributable to the Net Profits Interest is sold to
Eastern Marketing pursuant to the Gas Purchase Contract, under which, since
January 1, 2000, all such production is purchased at a purchase price per Mcf
equal to the Index Price, composed only of the Variable Price. See "The Net
Profits Interests - Gas Purchase Contract."
REGULATION OF NATURAL GAS
The natural gas industry has historically been highly regulated by state
and federal authorities. In the past, 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.
HEALTH, SAFETY, AND 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. The following subtopics discuss some of the principal forms of
health, safety, and environmental regulation to which the Underlying Properties
and operations thereon are subject. The costs of complying with these regulatory
requirements may burden the Net Profits Interests to the extent they arise out
of or are related to activities occurring on or in, or conditions existing on or
under, the Underlying Properties after the effective date of the Conveyances.
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 prior to the
effective date of the Conveyances. 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 current 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 as 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 (The Bank of New York after May 8, 2000), 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 owns 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 holders of 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 and liquidation 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 determines 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 is equal to the excess, if
any, (i) the cash that the Trust receives on or before the tenth day of the
third month after the end of each calendar quarter ending before the Trust is
dissolved and that is attributable to production from the Net Profits Interest
held by the Trust during that calendar quarter, plus, with certain exceptions,
any other cash receipts of the Trust during such quarter, over (ii) 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 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 Quarterly Record Date, which is 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. The Trustee generally is 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 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.
See "Federal Income Tax Matters".
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 a court would 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. This section provides a generalized summary of certain
federal income tax matters of general application relating to ownership and sale
of Depositary units by 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 also 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, 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, Eastern American obtained an
opinion of counsel for the benefit of the Trust, 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 certain 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.
Reports
Unitholders of record are provided informational tax packages in order to
permit computation of their taxable income from ownership of Depositary Units.
Treatment of Depositary Units
Purchasers of Depositary Units are treated, for Federal income tax
purposes, as purchasing directly an interest in the Treasury Obligations and a
Trust Unit. Purchasers are therefore required to allocate the purchase price of
their 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 is furnished to Unitholders by the Trustee.
Classification and Taxation of the Trust
For federal income tax purposes, the Trust has been treated and expects to
continue to be treated not as an association taxable as a corporation, but as a
grantor trust that is not subject to Federal income tax as an entity separate
from its beneficial owners. For tax purposes, Unitholders are considered to own
and receive the Trust's assets and income as though no trust were in existence.
The Trust files 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 not to be a grantor trust, it is expected that it would be
treated either as a partnership subject to the publicly traded partnership rules
under the Code or as an association taxable as a corporation. If the Trust were
treated as a publicly traded partnership, it is believed that the Trust's
various items of income and deduction would still be taxable to the Unitholders
on a current, flow-through basis as partners of a partnership and not to the
Trust as an association taxable as a corporation. 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 is treated as a grantor trust for Federal income
tax purposes, and Unitholders are treated for Federal income tax purposes as
owning a direct interest in the Treasury Obligations and the assets of the
Trust, each Unitholder is taxed directly on his pro rata share of the income
attributable to the Treasury Obligations and the assets of the Trust and is
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 are 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 must 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.
Under current market conditions, it is anticipated that total distributable
cash will exceed taxable income through 2004. After 2004, taxable income is
anticipated to 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 relationship between distributable cash and
taxable income could be materially higher or lower.
Treatment of Trust Units
On the assumption that the Trust is a grantor trust for Federal income tax
purposes, each Unitholder is treated as purchasing directly an interest in the
Net Profits Interests. Purchasers of Depositary Units must allocate the portion
of their 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 is 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, Unitholders are 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.
The IRS has issued a series of proposed and final 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 were proposed to
be effective for debt obligations issued on or after the date that is sixty days
following the promulgation of the New Proposed Regulations in final form. In
this regard, the New Proposed Regulations have been adopted in final form (the
"Final Regulations"), though effective only for debt instruments issued after
August 12, 1996. Thus, by their terms, the New Proposed Regulations and the
Final Regulations do not apply to the Term NPI. However, the Preamble to the
Final Regulations provides that for debt instruments issued prior to the
effective date of the Final Regulations, a taxpayer may use any reasonable
method to account for such debt instruments, including a method that would have
been permitted under the proposed regulations when the debt instrument was
issued.
The Trustee understands that, in accordance with the foregoing, 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 are also required to recognize and report OID interest income
attributable to the Treasury Obligations. In general, the total amount of OID a
Unitholder is 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
is included in income by a Unitholder on the basis of a constant interest rate
computation.
On March 23, 1999, the United States Tax Court of Appeals for the Tenth
Circuit affirmed a lower court decision in True Oil Company v. C.I.R. 170 F.3d
1294. The Court ruled that, in order to be eligible for credits under Section 29
of the Internal Revenue Code, each well from which gas is produced from Devonian
shale or a tight formation must receive a determination from the Federal Energy
Regulatory Commission ("FERC") that the gas produced is, in fact, produced from
Devonian shale or a tight formation. Eastern American has verified that most
producing gas wells subject to the Royalty NPI have received a well category
determination from FERC. Should the Internal Revenue Service challenge the
amount of the Trust's production qualifying for Section 29 Credits, a Unitholder
might not be able to claim the benefit of Section 29 credits for production
attributable to a well that did not receive a FERC determination. If successful,
such a challenge could affect the tax reporting for such credits for tax years
examined by the IRS and any subsequent tax years.
Royalty Income and Depletion
The income from the Royalty NPI is 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 tax
information reports that the Trust provides to Unitholders and the IRS have
reported all production attributable to the Royalty NPI as production
attributable to a single property for depletion purposes. Such reporting
treatment is expected to continue until at least the IRS position on such
treatment is changed.
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. A taxpayer's total percentage depletion
deduction for all properties 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. While the Trust is treated as a grantor trust for Federal income tax
purposes, each Unitholder computes cost depletion by using as his basis for the
property the portion of his cost basis for his Depositary Units that is
allocated first to the NPI and second to the Royalty NPI. Information is
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 is eligible to claim the Section 29 Credit with
respect to certain 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 and generally
may not be used to reduce a taxpayer's liability for alternative minimum tax.
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.
The Section 29 Credit is not available for production after December 31,
2002. Congress in past years has considered, without enacting, legislation to
extend energy tax credits such as the Section 29 Credit beyond their expiration
date or to create new similar credits. The potential effect that enactment of
any such possible legislation may have on Unitholders in the future is unknown.
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 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 are not 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 is not
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 is equal to the amount paid for such Depositary Units. Such basis is
increased by the amount of OID income recognized by the Unitholder attributable
to the Treasury Obligations. Such basis is reduced by deductions for depletion
claimed by the Unitholder (but not below zero). In addition, such basis is
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 is 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 are 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 is, in certain cases, 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 is reduced.
Backup Withholding
In general, distributions of Trust income are not 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 $250
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.
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 be subject to penalties for failure to comply with such
requirements. Generally, Unitholders may treat state income taxes that the Trust
has withheld as having been paid by them to the state for which they were
withheld. Unitholders may be able to treat any taxes that they have paid or that
have been withheld and paid to West Virginia or Pennsylvania as a deduction in
computing Federal income tax, or as a credit or a deduction in computing another
state's income tax.
Unitholders receive information concerning the Depositary Units and the
Trust Units sufficient to identify the income from Depositary Units that is
allocable to each state. Holders 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 and therefore also the Depositary Units may constitute real
property or an interest in real property under the tax, 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 ad valorem or other property tax,
devolution, probate and administration laws, and inheritance or estate and
similar taxes, under the laws of such state.
AVAILABLE INFORMATION
The Trust does not maintain an internet address or a website, and therefore
does not make copies of its reports under the Exchange Act available in that
manner. The Trust's filings under the Exchange Act are available electronically
from the website maintained by the Securities and Exchange Commission at
http://www.sec.gov. The Trust will also provide electronic copies of its recent
filings free of charge upon request to the Trustee, and will provide paper
copies of its recent filings for its costs of reproduction upon request to the
Trustee.
Item 2. Properties.
Reference is made to Item 1 of this Form 10-K.
Item 3. Legal Proceedings.
None
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, 2002.
PART II
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 distributions paid during the
quarters in the three-year period ended December 31, 2002 were as follows:
Quarter Distributions
------- High Low Paid
---- --- ----
2000:
-----
First (to March 31, 2000) $ 13 5/16 $ 10 3/8 $ 0.30
Second (to June 30, 2000) $ 14 5/16 $ 12 3/16 $ 0.37
Third (to September 30, 2000) $ 15 3/8 $ 13 15/16 $ 0.45
Fourth (to December 31, 2000) $ 16 3/4 $ 14 9/16 $ 0.54
2001:
-----
First (to March 31, 2001) $ 18.25 $ 16.00 $ 0.63
Second (to June 30, 2001) $ 19.95 $ 17.08 $ 0.56
Third (to September 30, 2001) $ 19.44 $ 16.91 $ 0.42
Fourth (to December 31, 2001) $ 19.38 $ 17.75 $ 0.30
2002:
-----
First (to March 31, 2002) $ 19.00 $ 17.22 $ 0.28
Second (to June 30, 2002) $ 18.40 $ 17.44 $ 0.33
Third (to September 30, 2002) $ 19.00 $ 16.50 $ 0.34
Fourth (to December 31, 2002) $ 19.22 $ 17.90 $ 0.37
At March 14, 2003, the 5,900,000 Depositary Units outstanding were held by
approximately 330 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, 2002 to December 31, 2002 were
$641.90 and $600.40, respectively. The closing asked price on December 31, 2002
was $637.10 per $1,000 face amount.
Item 6. Selected Financial Data.
December December December December December
31, 2002 31, 2001 31, 2000 31, 1999 31, 1998
----------- ----------- ----------- ----------- -----------
Distributable Income and other
Distributions Declared ........ $7,808,725 $11,268,383 $9,776,735 $8,561,984 $9,422,675
Distributable Income and other
Distributions Declared per unit $1.32 $1.91 $1.66 $1.45 $1.60
Total assets at year end ...... $41,006,654 $45,129,170 $50,964,669 $55,251,901 $61,009,470
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.
Under the Gas Purchase Contract, through the Primary Term ending December
31, 1999, Eastern Marketing purchased gas from the Trust at an Index Price
calculated based on a Fixed Price component (escalating at 5% a year and
carrying a 66-2/3% weighting) and a Variable Price component (varying with the
Henry Hub market price as described below and carrying a 33-1/3% weighting),
subject to a minimum Floor Price (as defined in the Gas Purchase Contract).
Since January 1, 2000, and the end of the Primary Term, Eastern Marketing has
purchased gas from the Trust at an Index Price composed only of the Variable
Price component, and not subject to any minimum Floor Price. 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 which is traded on the
New York Mercantile Exchange.
Accordingly, the price payable to the Trust for production may vary based
on 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 the
Unitholders.
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 year ended December 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 year ended
December 31, 2002.
Over the remaining life of the Trust, additional wells may need to be
disposed of for similar reasons.
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
2002 Compared with 2001
-----------------------
The Trust's total distributions declared per Unit were $1.32 for the twelve
months ended December 31, 2002 as compared to $1.91 for the twelve months ended
December 31, 2001. Such decrease was due to a decrease in the average price
payable to the Trust under the Gas Purchase Contract (as discussed below) and to
a decrease in production of gas attributable to the Net Profits Interests for
the twelve months ended December 31, 2002 (2,357 MMcf) as compared to the twelve
months ended December 31, 2001 (2,489 MMcf). The production decreases were
primarily attributable to the natural production declines associated with the
Underlying Properties together with the sale of wells. Taxes on production and
property were $613,115 for the twelve months ended December 31, 2002 as compared
to $900,951 for the twelve months ended December 31, 2001. This decrease was due
to the decrease in Royalty Income for the twelve months ended December 31, 2002
($9,024,646) as compared to the twelve months ended December 31, 2001
($13,260,202). The distributable income includes Cash Proceeds on Sale of Net
Profits Interest of $492,043 for the twelve months ended December 31, 2002,
while no such sales were recognized in the corresponding prior twelve months.
The average price payable to the Trust for gas production attributable to
the Net Profits Interests was $3.83 per Mcf for the twelve months ended December
31, 2002 as compared to $5.32 per Mcf for the twelve months ended December 31,
2001. The average price per Mcf was lower for the twelve months ended December
31, 2002 than the corresponding twelve month period ended December 31, 2001 due
to a decrease in the average spot market price for gas delivered at the Henry
Hub, near Henry, Louisiana ($3.18 per MMBtu for the twelve months ended December
31, 2002; $4.53 per MMBtu for the twelve months ended December 31, 2001).
2001 Compared with 2000
-----------------------
The Trust's total distributions declared per Unit were $1.91 for the twelve
months ended December 31, 2001 as compared to $1.66 for the twelve months ended
December 31, 2000. Such increase was due to an increase in the average price
payable to the Trust under the Gas Purchase Contract as discussed below ($5.32
per Mcf for the twelve months ended December 31, 2001; $4.27 per Mcf for the
twelve months ended December 31, 2000). This increase was partially offset by a
decrease in production of gas attributable to the Net Profits Interests for the
twelve months ended December 31, 2001 (2,489 MMcf) as compared to the twelve
months ended December 31, 2000 (2,717 MMcf). The production decreases were
primarily attributable to the natural production declines associated with the
Underlying Properties together with the effects of Dominion Transmission, Inc
(DTI) revised gas gathering and processing rates as filed with and approved by
the Federal Energy Regulatory Commission (FERC Docket No. RP 97-406) effective
January 1, 2001. The new rates provide for a percentage of gas to be retained by
DTI as shrink for gas moving through their gathering system(s) and for
extraction of liquids on gas production required to be processed in order to
meet the gas quality requirements of the pipeline transmission companies to
which gas is delivered.
The average price payable to the Trust for gas production attributable to
the Net Profits Interests was $5.32 per Mcf for the twelve months ended December
31, 2001 as compared to $4.27 per Mcf for the twelve months ended December 31,
2000. The average price per Mcf was higher for the twelve months ended December
31, 2001 than the corresponding twelve month period ended December 31, 2000 due
to an increase in the average spot market price for gas delivered at the Henry
Hub, near Henry, Louisiana ($4.53 per MMBtu for the twelve months ended December
31, 2001; $3.59 per MMBtu for the twelve months ended December 31, 2000).
Item 7A. Quantitative and Qualitative Disclosure 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 in detail 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 Item 5. As described
in detail 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 8. Financial Statements and Supplementary Data.
Page in this Form 10-K
Financial Statements
Report of Independent Accountants ......................................B-2
Statements of Assets, Liabilities and Trust Corpus as of
December 31, 2002 and 2001 ..........................................B-3
Statements of Distributable Income for the years ended
December 31, 2002, 2001 and 2000 ....................................B-4
Statements of Changes in Trust Corpus for the years ended
December 31, 2002, 2001 and 2000 ....................................B-5
Notes to Financial Statements ..........................................B-6
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III
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 of a
majority of the Trust Units then outstanding at a meeting of the Unitholders of
the Trust at which a quorum is present. The Trust is not required to and does
not hold annual meetings of the Unitholders.
Item 11. Executive Compensation.
The Trust has no officers or directors, and is administered by the Trustee.
For the years ended December 31, 2002, 2001 and 2000, the Trustee received
$45,000 annually, as Trustee fees and $263,713, $261,662 and $214,848,
respectively, as reimbursement of legal, accounting, and other professional
expenses for such services.
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 14, 2003.
(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 in
control of the Trust.
Item 13. Certain Relationships and Related Transactions.
None.
Item 14. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Trustee maintains disclosure controls and procedures designed to ensure
that information required to be disclosed by the Trust in the reports that it
files or submits under the 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 ensure that information required to be disclosed by
the Trust is accumulated and communicated by several parties, including without
limitation, the working interest owner, Eastern American Energy Corporation
("Eastern American"), and the independent reserve engineer 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.
Within 90 days of the date of this report, the Trustee carried out an
evaluation of the Trustee's disclosure controls and procedures. Cassandra Shedd,
as Agent of the Trustee, has concluded that the controls and procedures are
effective, 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 may be 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 others, including,
without limitation, 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.
Trustee does not intend to expand its responsibilities beyond those
permitted or required by the Trust Agreement and those required under applicable
law.
Changes in Internal Controls
To the knowledge of the Trustee, there have been no significant changes in
the Trust's internal controls or in other factors 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 IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
Reports Page in this Form 10-K
----------------------
Reserve Report of Ryder Scott Company, Independent
Petroleum Engineers ..............................................A-1 - A-7
Financial Statements
The following financial statements are included in this Annual Report on Form
10-K on the pages indicated:
Report of Independent Accountants ........................................B-2
Statements of Assets, Liabilities and Trust Corpus as of
December 31, 2002 and 2001 ............................................B-3
Statements of Distributable Income for the years ended
December 31, 2002, 2001 and 2000 ......................................B-4
Statements of Changes in Trust Corpus for the years ended
December 31, 2002, 2001 and 2000 ......................................B-5
Notes to Financial Statements .....................................B-6 - B-17
Schedules
All schedules have been omitted because they are not required, not applicable or
the information required has been included elsewhere herein.
Exhibits
Except as otherwise indicated below, all exhibits, except Exhibit 99.1, 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 3.1, which is incorporated by
reference to the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1994.
Exhibit
Number
------
3.1 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 Conveyance of Production Payment/Assignment of
Production from Eastern American Natural Gas Trust to
Eastern American Marketing Corporation ........................10.4
10.5 Form of Assignment and Standby Performance Agreement .............10.5
99.1 Certification pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 .......................................................99.1
Reports on Form 8-K
On November 19, 2002, the Trust filed a report on Form 8-K as certification
pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
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 20th day of
March, 2003.
EASTERN AMERICAN NATURAL GAS TRUST
By: The Bank of New York, Trustee
By: /s/ Richard Costantino
--------------------------------
Name: Richard Costantino
Title: Agent
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.
CERTIFICATION
I, Richard Costantino, certify that:
1. I have reviewed this annual report on Form 10-K of Eastern American
Natural Gas Trust, for which The Bank of New York acts as Trustee;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, distributable income and
changes in trust corpus of the registrant as of, and for, the
periods presented in this annual report;
4. I am responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14),
or for causing such controls and procedures to be established and
maintained, for the registrant and have:
a) designed such disclosure controls and procedures, or caused such
controls and procedures to be designed, to ensure that material
information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report my conclusion about the
effectiveness of the disclosure controls and procedures based on
my evaluation as of the Evaluation Date;
5. I have disclosed, based on my most recent evaluation, to the
registrant's auditors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves any persons who
have a significant role in the registrant's internal controls;
and
6. I have indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of my most
recent evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
In giving the foregoing certifications in paragraph 4, 5 and 6 above, I
have relied to the extent I consider reasonable on information provided to
me by Eastern American Energy Corporation and Ryder Scott Company,
Independent Petroleum Engineers.
/s/ Richard Costantino
--------------------------------
Senior Vice President
The Bank of New York
Date: March 31, 2003
[Ryder Scott Company, Independent Petroleum Engineers Letterhead]
January 21, 2003
Eastern American Natural Gas Trust
The Bank of New York
2 North LaSalle Street, Suite 1020
Chicago, Illinois 60606
Gentlemen:
Pursuant to your request, we present below estimates of the net proved
reserves attributable to the interests of the Eastern American Natural Gas Trust
(Trust) as of December 31, 2002. The Trust is a grantor trust formed to hold
interests in certain domestic oil and gas properties owned by Eastern American
Energy Corporation (EAEC), a wholly owned subsidiary of Energy Corporation of
America (ECA). The interests conveyed to the Trust consist of a net profits
interest derived from working and royalty interests in numerous properties. The
Net Profits Interest consists of (1) a life-of-properties interest ("Royalty
NPI") and (2) a term interest ("Term NPI"). The properties included in the Trust
are located in the states of Pennsylvania and West Virginia.
The estimated reserve quantities and future income quantities
presented in this report are related to a large extent to hydrocarbon prices.
Hydrocarbon prices in effect at December 31, 2002 were used in the preparation
of this report as required by Securities and Exchange Commission (SEC) and
Financial Accounting Standards Bulletin No. 69 (FASB 69) guidelines; however,
actual future prices may vary significantly from December 31, 2002 prices for
reasons discussed in more detail in other sections of this report. Therefore,
quantities of reserves actually recovered and quantities of income actually
received may differ significantly from the estimated quantities presented in
this report.
As of December 31, 2002
-------------------------
Estimated Present
Future Net Value
Gas Cash Inflows At 10%
(MMCF) (M$) (M$)
------ ------------ ------
Proved Net Developed
Royalty NPI 12,025 53,743 22,953
Term NPI 8,609 38,472 25,358
------ ------ ------
Total 20,634 92,215 48,311
Reserve quantities are calculated differently for a Net Profits
Interest because such interests do not entitle the Trust to a specific quantity
of oil or gas but to 90 percent of the Net Proceeds derived therefrom beginning
on January 1, 2003 for natural gas. Accordingly, there is no precise method of
allocating estimates of the quantities of proved reserves attributable to the
Net Profits Interest between the interest held by the Trust and the interests to
be retained by EAEC. 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. Accordingly, the
reserves presented for the Net Profits Interest reflect quantities of gas that
are free of future costs or expenses based on the price and cost assumptions
utilized in this report. The allocation of proved reserves of the Net Profits
Interest between the Trust and EAEC will vary in the future as relative
estimates of future gross revenues and future net incomes vary. Furthermore,
EAEC requested that for purposes of our report the "Royalty NPI" be calculated
beyond the Liquidation Date of May 15, 2013, even though by the terms of the
Trust Agreement the Royalty NPI will be sold by the Trustee on or about this
date and a liquidating distribution of the sales proceeds from such sale would
be made to holders of Trust Units. For purposes of this report, the "Term NPI"
was limited to the 20 year period defined as the term by the Trust.
All gas volumes are sales gas expressed in MMCF at the pressure and
temperature bases of the area where the gas reserves are located. The estimated
future net cash inflows are described later in this report.
The proved reserves presented in this report comply with the
Securities and Exchange Commission's Regulation S-X Part 210.4-10 Sec. (a) as
clarified by subsequent Commission Staff Accounting Bulletins, and are based on
the following definitions and criteria:
Proved reserves of crude oil, natural gas, or natural gas liquids
are estimated quantities that geological and engineering data demonstrate
with reasonable certainty to be recoverable in the future from known
reservoirs under existing conditions. Reservoirs are considered proved if
economic producibility is supported by actual production or formation
tests. In certain instances, proved reserves may be assigned on the basis
of a combination of core analysis and electrical and other type logs which
indicate the reservoirs are analogous to reservoirs in the same field which
are producing or have demonstrated the ability to produce on a formation
test. The area of a reservoir considered proved includes (1) that portion
delineated by drilling and defined by fluid contacts, if any, and (2) the
adjoining portions not yet drilled that can be reasonably judged as
economically productive on the basis of available geological and
engineering data. In the absence of data on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the lower proved limit
of the reservoir. Proved reserves are estimates of hydrocarbons to be
recovered from a given date forward. They may be revised as hydrocarbons
are produced and additional data becomes available. Proved natural gas
reserves consist of non-associated, associated and dissolved gas. An
appropriate reduction in gas reserves has been made for the expected
removal of natural gas liquids, for lease and plant fuel, and for the
exclusion of non-hydrocarbon gases if they occur in significant quantities.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Estimates of proved reserves do not include crude oil, natural gas, or
natural gas liquids being held in underground or surface storage.
(i) "developed reserves" which are those proved reserves
reasonably expected to be recovered through existing wells with
existing equipment and operating methods, including (a)
"developed producing reserves" which are those proved developed
reserves reasonably expected to be produced from existing
completion intervals now open for production in existing wells,
and (b) "developed non-producing reserves" which are those proved
developed reserves which exist behind the casing of existing
wells which are reasonably expected to be produced through these
wells in the predictable future where the cost of making such
hydrocarbons available for production should be relatively small
compared to the cost of a new well; and
(ii) "undeveloped reserves" which are those proved reserves
reasonably expected to be recovered from new wells on undrilled
acreage, from existing wells where a relatively large expenditure
is required and from acreage for which an application of fluid
injection or other improved recovery technique is contemplated
where the technique has been proved effective by actual tests in
the area in the same reservoir. Reserves from undrilled acreage
are limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units are included only where it can
be demonstrated with reasonable certainty that there is
continuity of production from the existing productive formation.
In accordance with the requirements of FASB 69, estimates of future cash
inflows, future costs and future net cash inflows before income tax, as well as
estimated reserve quantities, as of December 31, 2002 from this report are
presented in the following table:
As of December 31, 2002
-----------------------
Royalty Term
NPI NPI Totals
------ ------ ------
Total Proved
Future Cash Inflows (M$) 53,743 38,472 92,215
Future CostsProduction (M$) 0 0 0
Development (M$) 0 0 0
------ ------ ------
Total Costs (M$) 0 0 0
Future Net Cash Inflows
Before Income Tax (M$) 53,73 38,472 92,215
Present Value at 10%
Before Income Tax (M$) 22,953 25,358 48,311
As of December 31, 2002
-----------------------
Royalty Term
NPI NPI Totals
------ ------ ------
Proved Net Developed Reserves
Gas (MMCF) 12,025 8,609 20,634
Proved Net Undeveloped Reserves
Gas (MMCF) 0 0 0
Total Proved Net Reserves
Gas (MMCF) 12,025 8,609 20,634
For Net Profits Interest, the future cash inflows are, as described
previously, after consideration of future costs or expenses based on the price
and cost assumptions utilized in this report. Therefore, the future cash inflows
are the same as the future net cash inflows. The effects of depreciation,
depletion and federal income taxes have not been taken into account in
estimating future net cash inflows.
EAEC furnished us gas prices in effect at December 31, 2002 and with its
forecasts of future gas prices which take into account Securities and Exchange
Commission guidelines, current market prices, contract prices and fixed and
determinable price escalations where applicable. In accordance with Securities
and Exchange Commission guidelines, the future gas prices used in this report
make no allowances for future gas price increases or decreases which may occur
as a result of inflation nor do they account for seasonal variations in gas
prices which are likely to cause future yearly average gas prices to be somewhat
higher than December gas prices. In those cases where contract market-out has
occurred, the current market price was held constant to depletion of the
reserves. In those cases where market-out has not occurred, contract gas prices
including fixed and determinable escalations, exclusive of inflation
adjustments, were used until the contract expired and determinable escalations,
exclusive of inflation adjustments, were used until the contract expired and
then reduced to the current market price for similar gas in the area and held at
this reduced price to depletion of the reserves.
This report utilized the terms of the gas contract between Eastern
Marketing and the Trust. Gas price is to be determined by a weighted price
consisting of two components during a primary term defined to begin on January
1, 1993 and end December 31, 1999. The first component is the "Fixed" price
which has been defined as $2.66 per Mcf beginning January 1, 1993. This price
escalates 5 percent per year on January 1 of each year during the primary term
beginning in 1994. The second component is the "Variable" price which for any
quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu,
plus $0.30 per MMBtu, multiplied by 110 percent to effect a Btu adjustment. The
Henry Hub Average Spot Price is defined as the price per MMBtu determined for
any calendar quarter as the average price of the three months in such quarter
where each month's price 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 each month of such quarter, (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 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. The weighted average price is
determined by giving the "Fixed" price a 66 2/3 percent weighting and the
variable price a 33 1/3 percent weighting.
Since the primary term is complete, the purchase price under the gas
contract will be equal to the "Variable" price. EAEC computed the "Variable"
price under the gas contract as of December 31, 2002 as $4.469 per Mcf,
utilizing $3.763 as the Henry Hub Average Spot Price computed in accordance with
the gas contract.
Operating costs for the leases and wells in this report were supplied by
EAEC and include only costs defined as applicable under terms of the Trust. The
current operating costs were held constant throughout the life of the
properties. This study does not consider the salvage value of the lease
equipment or the abandonment cost.
No deduction was made for indirect costs such as general administration and
overhead expenses, loan repayments, interest expenses, and exploration and
development prepayments. No attempt has been made to quantify or otherwise
account for any accumulated gas production imbalances that may exist.
Our reserve estimates are based upon a study of the properties in which the
Trust has interests; however, we have not made any field examination of the
properties. No consideration was given in this report to potential environmental
liabilities which may exist nor were any costs included for potential liability
to restore and clean up damages, in any, caused by past operating practices.
EAEC informed us that it has furnished us all of the accounts, records,
geological and engineering data and reports and other data as were required for
our investigation. The ownership interests, terms of the Trust, prices, taxes,
classification of wells for Section 29 Tax Credit, and other factual data
furnished to us in connection with our investigation were accepted as
represented. The estimates presented in this report are based on data available
through March, 2002. The projections were developed for the EAEC reserve report
effective July 1, 2002. EAEC has advised Ryder Scott that there has been no
material change in the performance of these wells and therefore the July 1, 2002
projections developed for the EAEC report were mechanically adjusted to January
1, 2003 for use in this report.
At the time of formation of the Trust, EAEC assigned The Trust an interest
in 65 undeveloped locations. During the period 1993 through 1998, EAEC has
completed it's drilling obligation. A total of 59 wells were drilled over this
period. Two wells were not drilled due to title failure and four wells were not
drilled due to short spacing. Reserves and projections of future production are
included for the four locations which were not drilled due to short spacing.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered.
Moreover, estimates of proved reserves may increase or decrease as a result of
future operations of EAEC. Moreover, due to the nature of the Net Profits
Interest, a change in the future costs, or prices different from those projected
herein may result in a change in the computed reserves and the Net Proceeds to
the Trust even if there are no revisions or additions to the gross reserves
attributed to the property.
The future production rates from properties now on production may be more
or less than estimated because of changes in market demand or allowables set by
regulatory bodies. Properties which are not currently producing may start
producing earlier or later than anticipated in our estimates of their future
production rates.
The future prices received by EAEC for the sale of its production may be
higher or lower than the prices used in this report as described above, and the
operating costs and other costs relating to such production may also increase or
decrease from existing levels; however, such possible changes in prices and
costs were, in accordance with rules adopted by the Securities and Exchange
Commission, omitted from consideration in preparing this report.
At the request of EAEC, we have included the following table which
summarizes the total net reserves estimates from combined interest of EAEC and
the Trust in the Underlying Properties:
Estimated Net Reserve Data
Certain Combined Leasehold Interests of
Eastern America Energy CorporationAnd The Trust
As of December 31, 2002 SEC Parameters
--------------
Proved
-----------------------------
Total
Developed Undeveloped Proved
--------- ----------- ------
Net Remaining Reserves
----------------------
Gas-MMCF 40,904 0 40,904
The estimated future net income associated with the foregoing volumes and
the 10 percent discounted estimated future net income was $143,931,312 and
$59,962,971, respectively. This evaluation utilizes the same price and cost
assumptions that were utilized for evaluating the Trust and discussed earlier in
the letter. The properties which are included in the "Term NPI" were allowed to
run for their full economic life in this evaluation.
Neither Ryder Scott Company nor any of its employees has any interest in
the subject properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future cash inflows
for the subject properties.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
Larry T. Nelms P. E.
Senior Vice President
LTN:ph
EASTERN AMERICAN NATURAL GAS TRUST
----------
FINANCIAL STATEMENTS
as of December 31, 2002 and 2001
and for the years ended
December 31, 2002, 2001 and 2000
REPORT OF INDEPENDENT ACCOUNTANTS
To the Unitholders and The Bank of New York,
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,
2002 and 2001, and the related statements of distributable income, and changes
in trust corpus for each of the three years in the period ended December 31,
2002. 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 auditing standards generally accepted
in the United States of America. 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 the basis of accounting prescribed by the Trust Agreement.
In our opinion, the financial statements audited by us present fairly, in all
material respects, the financial position of the Trust at December 31, 2002 and
2001, and the distributable income and changes in trust corpus for each of the
three years in the period ended December 31, 2002, on the basis of accounting
described in Note 2.
/s/ PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
March 17, 2003
EASTERN AMERICAN NATURAL GAS TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
for the years ended
December 31, 2002, 2001 and 2000
2002 2001 2000
------------- ------------- -------------
Royalty Income $9,024,646 $13,260,202 $11,569,718
Operating Expenses:
Taxes on production and property 613,115 900,951 784,871
Operating cost charges 501,738 513,107 488,672
------------- ------------- -------------
Total Operating Expenses 1,114,853 1,414,058 1,273,543
------------- ------------- -------------
Net Proceeds to the Trust 7,909,793 11,846,144 10,296,175
General and Administrative
Expenses (594,921) (583,190) (527,028)
Interest Income 1,810 5,429 7,588
Cash Proceeds on Sale of
Net Profits Interest 492,043 0 0
------------- ------------- -------------
Distributable Income $7,808,725 $11,268,383 $9,776,735
============= ============= =============
Distributable Income Per Unit
(5,900,000 units authorized
and outstanding) $1.3235 $1.9099 $1.6571
============= ============= =============
The accompanying notes are an integral part of these financial statements.
EASTERN AMERICAN NATURAL GAS TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
as of December 31, 2002 and 2001
2002 2001
---------------- ----------------
Assets:
Cash $ 406 $ 1,201
Net Proceeds Receivable 2,310,449 1,957,988
Net Profits Interests in Gas Properties 93,162,180 93,162,180
Accumulated Amortization (54,466,381) (49,992,199)
---------------- ----------------
Total Assets $41,006,654 $45,129,170
================ ================
Liabilities and Trust Corpus:
Trust General and Administrative
Expenses Payable $ 145,098 $ 172,034
Distributions Payable 2,165,757 1,787,155
Trust Corpus (5,900,000 Trust Units
authorized and outstanding) 38,695,799 43,169,981
---------------- ----------------
Total Liabilities and Trust Corpus $41,006,654 $45,129,170
================ ================
The accompanying notes are an integral part of these financial statements.
EASTERN AMERICAN NATURAL GAS TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
for the years ended
December 31, 2002, 2001 and 2000
2002 2001 2000
------------- ------------- -------------
Trust Corpus, Beginning of Period $43,169,981 $47,650,950 $53,087,803
Distributable Income 7,808,725 11,268,383 9,776,735
Distributions Paid or Payable to
Unitholders (7,808,725) (11,268,383) (9,776,735)
Amortization of Net Profits
Interests in Gas Properties (4,474,182) (4,480,969) (5,436,853)
------------- ------------- -------------
Trust Corpus, End of Period $38,695,799 $43,169,981 $47,650,950
============= ============= =============
The accompanying notes are an integral part of these financial statements.
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, 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 Bank of
Montreal Trust Company. As a result, The Bank of New York serves as Trustee (the
"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.
Eastern American drilled 59 of the 65 development wells.
Four (4) of the remaining six (6) development wells were closely offset by third
parties. Since the wells drilled by the third parties were within 1,000 feet of
these development wells, Eastern American had a disagreement with the Trust over
Eastern American's obligation to drill these closely offset development wells.
The Trust has agreed that, in lieu of drilling these closely offset development
wells Eastern American can 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 the Ryder Scott Company.
The two (2) remaining development wells were not drilled because Eastern
American was unable to cure various title defects associated with these wells.
Eastern American advised the Trust that it made a diligent effort to cure title
but was unsuccessful. In West Virginia, an oil and gas well cannot be drilled
unless a full and complete 100% leasehold interest is first obtained. Drilling
an oil and gas well without obtaining the entire leasehold estate would expose
the oil and gas operator and the Trust to a possible suit for trespass. Pursuant
to the Term Net Profits Interest Conveyance, if the state of title to the drill
site to any development well renders such property undrillable in the good faith
opinion of Eastern American under the Reasonably Prudent Operator Standard then
such drill site(s) shall be construed as a development well(s). Consequently,
Eastern American has fulfilled its commitment to the Trust to drill the required
number of development wells.
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 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.
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 accounting principles generally accepted in the United States
of America due to the following; i) certain cash reserves may be established for
contingencies which were not accrued in the financial statements; ii)
amortization of the Net Profits Interests in gas properties is charged directly
to Trust Corpus; and iii) the sale of the Net Profits Interests is reflected in
the Statements of Distributable Income as cash proceeds to the Trust.
Cash:
Cash consists of highly liquid instruments with maturities at the time of
acquisition of three months or less.
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 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.
Significant dispositions or abandonment 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. Revisions to estimated future
units-of-production are treated on a prospective basis beginning on the date
significant revisions are known.
The conveyance of the Royalty and Term Interests to the Trust was accounted for
as a purchase transaction. The $93,162,180 reflected in the Statement of Assets,
Liabilities and Trust Corpus as Net Profits Interests represents 5,900,000 Trust
Units valued at $20.50 per depository unit less the $27,787,820 paid for
Treasury obligations. The carrying value of the Trust's investment in the
Royalty Interests is not necessarily indicative of the fair value of such
Royalty Interests.
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
election 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.
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. Operating expenses which
include taxes on production and operating cost charges are recognized as
incurred pursuant to the Conveyances on a per well production 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 the Trust to make estimates and
assumptions that affect the reported amounts of assets and liabilities and the
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Segment Information:
In 1998, the Trust adopted SFAS 131, "Disclosure about Segments of an Enterprise
and Related Information." The Trust's sole activity is earning royalty income
from gas properties and, consequently, the Trust has only one operating segment,
net profits interests in gas properties. Substantially all of the Trust's net
profits interests are located in the Appalachian region.
3. Income Taxes:
Tax counsel to the Trust advised the Trust at the time of formation that, under
then current tax laws, the Trust would be classified as a grantor trust for
federal and state income tax purposes and, therefore, would not be subject to
taxation at the Trust level. The Trust continues to be tax exempt. 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 credits
are 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.
Net proceeds receivable included in the Statements of Assets, Liabilities and
Trust Corpus as of December 31, 2002 and December 31, 2001 were received by the
Trust and distributed to the Unitholders on March 17, 2003 and March 15, 2002,
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 $308,713 for the year ended December 31, 2002, $306,662 for the
year ended December 31, 2001, and $259,848 for the year ended December 31, 2000.
In accordance with the Trust Agreement, the Trustee pays Eastern American an
annual fee which increases by 3.5% per year, payable quarterly, to reimburse
Eastern American for overhead expenses. The initial fee at the inception of the
Trust was $210,000. The Trustee paid Eastern American $286,208, $276,528 and
$267,180 for overhead expenses for 2002, 2001 and 2000 respectively. Operating
cost charges included in the Statements 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, as defined below, or a Floor Price, for gas produced in any
quarter during the Primary Term, which ended December 31, 1999. Effective
January 1, 2000, Eastern Marketing is obligated to purchase such gas production
at a purchase price per Mcf equal to the Index Price for gas produced in any
quarter after the Primary Term.
The Index Price for any quarter subsequent to the Primary Term, which expired
December 31, 1999, 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 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.
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.
6. Treasury Obligations:
The Treasury Obligations are directly owned by the Unitholders and are not part
of the Trust Corpus. The Treasury Obligations are on deposit with the Trustee
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, 2000 $443.70 $396.70
Quarter ended June 30, 2000 454.70 420.40
Quarter ended September 30, 2000 474.10 447.80
Quarter ended December 31, 2000 515.50 460.90
Quarter ended March 31, 2001 $532.30 $501.20
Quarter ended June 30, 2001 524.90 494.30
Quarter ended September 30, 2001 549.30 503.70
Quarter ended December 31, 2001 577.70 513.60
Quarter ended March 31, 2002 $548.40 $516.20
Quarter ended June 30, 2002 566.40 518.10
Quarter ended September 30, 2002 644.20 560.70
Quarter ended December 31, 2002 641.90 600.40
On December 31, 2002, 2001 and 2000, the closing price of the Treasury
Obligations, as quoted on such market, was $637.10, $526.10 and $509.90,
respectively.
The Trust provides Unitholders with the option to separate the related Treasury
Obligation from the Trust Units. Upon exercising this option, the Unitholder
receives the related Treasury obligation. As of December 31, 2002 and 2001, this
option was exercised on Trust Units of 107,900 and 7,900 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. Such 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.
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 were used during the Primary Term, which ended
December 31, 1999. The gas prices used thereafter are based solely on the fourth
quarter Variable gas price component.
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.
The following table reconciles the change in proved reserves attributable to the
Trust's share of the Net Profits Interests ("NPI") from January 1, 2000 to
December 31, 2002:
Royalty Term Total
NPI NPI NPI
(MMcf) (MMcf) (MMcf)
------- ------- -------
Balance, January 1, 2000 14,248 12,286 26,534
Production (1,187) (1,530) (2,717)
Revisions of previous estimates 1,922 728 2,650
------- ------- -------
Balance, December 31, 2000 14,983 11,484 26,467
Production (1,068) (1,421) (2,489)
Revisions of previous estimates (1,011) (222) (1,233)
------- ------- -------
Balance, December 31, 2001 12,904 9,841 22,745
Production (1,034) (1,324) (2,357)
Revisions of previous estimates (155) (92) (246)
------- ------- -------
Balance, December 31, 2002 12,025 8,609 20,634
======= ======= =======
The Trust's share of proved developed gas reserves are as follows:
Royalty Term Total
NPI NPI NPI
(MMcf) (MMcf) (MMcf)
------- ------- -------
December 31, 2000 14,983 11,484 26,467
====== ====== ======
December 31, 2001 12,904 9,841 22,745
====== ====== ======
December 31, 2002 12,025 8,609 20,634
====== ====== ======
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, 2002 (in thousands):
Royalty Term Total
NPI NPI NPI
------- ------- -------
Future cash inflows $69,983 $44,562 $114,545
Future production taxes (3,839) (2,104) (5,943)
Future production costs (12,400) (3,986) (16,386)
------- ------- -------
Future net cash inflows 53,743 38,472 92,215
10% discount factor (30,790) (13,114) (43,904)
------- ------- -------
Standardized measure of discounted
future net cash flows $22,953 $25,358 $48,311
======= ======= =======
The following is the standardized measure of discounted future net cash flows as
of December 31, 2001 (in thousands):
Royalty Term Total
NPI NPI NPI
------- ------- -------
Future cash inflows $61,197 $41,224 $102,421
Future production taxes (3,334) (1,916) (5,249)
Future production costs (11,924) (4,275) (16,199)
------- ------- -------
Future net cash inflows 45,939 35,033 80,973
10% discount factor (25,930) (12,614) (38,545)
------- ------- -------
Standardized measure of
discountedfuture net cash flows $20,009 $22,419 $42,428
======= ======= =======
The following is the standardized measure of discounted future net cash flows as
of December 31, 2000 (in thousands):
Royalty Term Total
NPI NPI NPI
------- ------- -------
Future cash inflows $101,949 $72,235 $174,184
Future production taxes (5,607) (3,324) (8,931)
Future production costs (13,127) (5,131) (18,258)
------- ------- -------
Future net cash inflows 83,215 63,780 146,995
10% discount factor (48,141) (24,134) (72,275)
------- ------- -------
Standardized measure of
discounted future net cash flows $35,074 $39,646 $74,720
======= ======= =======
Changes in Standardized Measure of Discounted Future Net Cash Flows:
The following schedule reconciles the changes during 2000, 2001 and 2002 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, 2000 $20,242 $24,066 $44,308
Net proceeds to the Trust (5,829) (4,468) (10,297)
Revisions of previous estimates 5,426 2,055 7,481
Accretion of discount 2,024 2,407 4,431
Net change in price and production costs 15,062 12,405 27,467
Other (1,851) 3,181 1,330
-------- -------- --------
Standardized measure, December 31, 2000 $35,074 $39,646 $74,720
Net proceeds to the Trust (6,721) (5,125) (11,846)
Revisions of previous estimates (1,886) (414) (2,300)
Accretion of discount 3,507 3,965 7,472
Net change in price and production costs (13,327) (9,638) (22,965)
Other 3,362 (6,015) (2,653)
-------- -------- --------
Standardized measure, December 31, 2001 $20,009 $22,419 $42,428
Net proceeds to the Trust (4,610) (3,300) (7,910)
Revisions of previous estimates 363 215 578
Accretion of discount 2,001 2,242 4,243
Net change in price and production costs 5,650 4,054 9,704
Other (460) (272) (732)
-------- -------- --------
Standardized measure, December 31, 2002 $22,953 $25,358 $48,311
======== ======== ========
8. Quarterly Financial Data (Unaudited):
The following is a summary of royalty income and distributable income declared
per unit by quarter in 2002, 2001 and 2000 (all amounts in thousands except
Distributable income per unit):
2002 Mar 31 June 30 Sept 30 Dec 31 Total
------- ------- ------- ------- -------
Royalty income $1,771 $2,192 $2,449 $2,612 $9,025
Distributable income $1,663 $1,950 $2,030 $2,166 $7,809
Distributable income per unit $0.2819 $0.3305 $0.3440 $0.3671 $1.3235
2001 Mar 31 June 30 Sept 30 Dec 31 Total
------- ------- ------- ------- -------
Royalty income $4,307 $3,840 $2,872 $2,241 $13,260
Distributable income $3,726 $3,311 $2,444 $1,787 $11,268
Distributable income per unit $0.6315 $0.5612 $0.4143 $0.3029 $1.9099
2000 Mar 31 June 30 Sept 30 Dec 31 Total
------- ------- ------- ------- -------
Royalty income $2,216 $2,577 $3,090 $3,687 $11,570
Distributable income $1,763 $2,190 $2,639 $3,185 $9,777
Distributable income per unit $0.2988 $0.3712 $0.4473 $0.5398 $1.6571
02662.0161 #394556v4