AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OCTOBER 15, 1999

REGISTRATION NO. 333-85955

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

AMENDMENT NO. 1

FORM S-1/S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

APPALACHIAN NATURAL GAS TRUST

(Exact name of registrant as specified in its charter)

DELAWARE 1311 75-6550504
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)

BANK ONE TEXAS, N.A.
500 THROCKMORTON, SUITE 801
FORT WORTH, TEXAS 76102
(817) 884-4417
ATTN: CORPORATE TRUST DEPARTMENT
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)
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EASTERN STATES OIL & GAS, INC.
(Exact name of registrant as specified in its charter)

DELAWARE 1311 61-1093943
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)

2800 EISENHOWER AVENUE
ALEXANDRIA, VIRGINIA 22314
(703) 317-2300
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)
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AS TO BOTH REGISTRANTS:
CLIFTON A. BROWN
PRESIDENT AND CHIEF EXECUTIVE OFFICER
2800 EISENHOWER AVENUE
ALEXANDRIA, VIRGINIA 22314
(703) 317-2300
(Name, address, including zip code, and telephone number, including area code,
of agent for service)

Copies to:

ANDREWS & KURTH L.L.P. BAKER & BOTTS, L.L.P.
600 TRAVIS, SUITE 4200 ONE SHELL PLAZA
HOUSTON, TEXAS 77002 910 LOUISIANA
(713) 220-4200 HOUSTON, TEXAS 77002
ATTN: G. MICHAEL O'LEARY (713) 229-1234
ATTN: JOSHUA DAVIDSON

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, please check the following box. [ ]

If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]

If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
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CALCULATION OF REGISTRATION FEE

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PROPOSED MAXIMUM
AGGREGATE AMOUNT OF
TITLE OF EACH CLASS OF SECURITIES TO BE REGISTERED OFFERING PRICE(1)(2) REGISTRATION FEE
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Units of beneficial interests............................... $190,181,250 $52,871(3)

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(1) Includes trust units issuable upon exercise of the underwriters'
over-allotment option.

(2) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457(o).

(3) A portion of this filing fee, $50,040, was previously paid in connection
with the initial filing of this registration statement on August 26, 1999.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
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THE INFORMATION IN THIS PRELIMINARY PROSPECTUS IS NOT COMPLETE AND MAY BE
CHANGED. THESE SECURITIES MAY NOT BE SOLD UNTIL THE REGISTRATION STATEMENT FILED
WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PRELIMINARY
PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN
OFFER TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT
PERMITTED.

Subject to Completion, dated October 15, 1999

PROSPECTUS

APPALACHIAN NATURAL GAS TRUST

7,875,000 TRUST UNITS

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This is an initial public offering of units of beneficial interest in the
Appalachian Natural Gas Trust. Eastern States Oil & Gas, Inc., an indirect
wholly owned subsidiary of Statoil Energy Inc., has formed the trust and is
offering all of the trust units to be sold in this offering. Eastern States will
receive all proceeds from the offering. The trust will not receive any proceeds
from the offering. Eastern States will continue to own 2,625,000 trust units
after this offering, or 1,443,750 trust units if the underwriters'
over-allotment option is exercised in full.

Prior to this offering there has been no public market for the trust units.
Eastern States expects that the offering price will be between $19.00 and $21.00
per trust unit. Eastern States has applied to have the trust units listed on the
New York Stock Exchange under the symbol "ANG."

THE TRUST UNITS. Trust units are units of beneficial ownership of the trust
and represent undivided beneficial interests in the assets of the trust.
They do not represent any interest in Eastern States or Statoil Energy.

THE TRUST. The trust owns net profits interests in natural gas producing
properties located in the Appalachian Basin area of Kentucky and West
Virginia. The net profits interests entitle the trust to receive:

- 80% of Eastern States' net proceeds from the sale of the production from
2,471 producing wells; and

- 10% of Eastern States' net proceeds from the sale of the production from
all wells drilled on or after September 1, 1999 on the leases in Kentucky
and West Virginia that are subject to the net profits interest.

THE TRUST UNITHOLDERS. As a trust unitholder, you will receive quarterly
distributions of cash that the trust receives attributable to its net
profits interests from the sale of natural gas produced from the underlying
properties.

INVESTING IN THE TRUST UNITS INVOLVES RISKS. RISK FACTORS BEGIN ON PAGE 16.

PER TRUST UNIT TOTAL
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Public offering price............................ $ $
Underwriting discount............................ $ $
Proceeds, before expenses, to Eastern States..... $ $

Eastern States has also granted the underwriters the right to purchase up
to an additional 1,181,250 trust units at the initial public offering price less
the underwriting discount to cover over-allotments.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS IS ACCURATE OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.

Lehman Brothers expects to deliver the trust units on or about
, 1999.
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JOINT BOOK-RUNNING MANAGERS

LEHMAN BROTHERS SALOMON SMITH BARNEY
CO-LEAD MANAGER
PAINEWEBBER INCORPORATED
CIBC WORLD MARKETS
CREDIT SUISSE FIRST BOSTON
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
DONALDSON LUFKIN & JENRETTE
A.G. EDWARDS & SONS, INC.
MCDONALD INVESTMENTS INC.
, 1999
3

[MAP OF UNDERLYING PROPERTIES APPEARS HERE]

No dealer, salesperson or other person is authorized to give any
information or to represent anything not contained in this prospectus. You must
not rely on any unauthorized information or representations. This prospectus is
an offer to sell the trust units offered hereby, but only under circumstances
and in jurisdictions where it is lawful to do so. The information contained in
this prospectus is current only as of its date.

Through and including , 1999 (the 25th day after the date of
this prospectus), all dealers effecting transactions in these securities,
whether or not participating in this offering, may be required to deliver a
prospectus. This is in addition to a dealer's obligation to deliver a prospectus
when acting as an underwriter and with respect to an unsold allotment or
subscription.
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TABLE OF CONTENTS

Prospectus Summary.......................................... 1
Risk Factors................................................ 16
Forward-Looking Statements.................................. 23
Use of Proceeds............................................. 23
Eastern States.............................................. 24
The Trust................................................... 25
Projected Year 2000 Distributable Cash...................... 25
The Underlying Properties................................... 34
Computation of Net Proceeds................................. 51
Federal Income Tax Consequences............................. 54
State Tax Considerations.................................... 58
ERISA Considerations........................................ 60
Description of the Trust Agreement.......................... 60
Description of the Trust Units.............................. 65
Underwriting................................................ 68
Selling Trust Unitholder.................................... 70
Validity of the Trust Units................................. 70
Experts..................................................... 71
Available Information....................................... 71
Glossary of Oil and Natural Gas Terms....................... 72
Index to Financial Statements............................... F-1
Information About Eastern States Oil & Gas, Inc. ........... A-1
Index to Financial Statements of Eastern States Oil & Gas,
Inc. ..................................................... AF-1
Ryder Scott Company, L.P. Reserve Report for the Underlying
Properties................................................ XA-1
Ryder Scott Company, L.P. Reserve Report for the Net Profits
Interest.................................................. XB-1

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PROSPECTUS SUMMARY

This summary may not contain all of the information that is important to
you. To understand this offering fully, you should read the entire prospectus
carefully, including the risk factors and the financial statements and notes to
those statements. You will find definitions for terms relating to the oil and
natural gas business in "Glossary of Oil and Natural Gas Terms." Ryder Scott
Company, L.P., an independent engineering firm, estimated the proved natural gas
reserves at August 31, 1999 for the underlying properties and the trust's net
profits interests included in this prospectus. Copies of their reserve reports
as of August 31, 1999 are located at the back of this prospectus as Exhibits A
and B. Historically, more than 99% of production from the underlying properties
has been natural gas and less than 1% has been oil. The net profits interests
conveyed to the trust will also include net proceeds from the sale of oil
production from the underlying properties. For purposes of this prospectus,
Eastern States uses the phrase "sale of natural gas from the underlying
properties" to also include the sale of oil from the underlying properties.

APPALACHIAN NATURAL GAS TRUST

Appalachian Natural Gas Trust was formed in August 1999 by Eastern States
under the Delaware Business Trust Act. Eastern States is the largest owner of
proved natural gas reserves, and believes it is one of the lowest cost
producers, in the Appalachian Basin. Eastern States is a wholly owned subsidiary
of Statoil Energy. Statoil Energy owns and operates power plants in the
northeast and mid-Atlantic regions of the United States, is a leading trader of
wholesale electricity and natural gas and specializes in providing a broad range
of energy and risk management services involving the delivery of natural gas,
electricity and alternative fuels to large industrial, institutional and
commercial customers.

Eastern States will transfer to the trust, as of September 1, 1999, an 80%
net profits interest in 2,471 producing natural gas wells in Kentucky and West
Virginia and a 10% net profits interest in wells drilled on or after September
1, 1999 on substantially all of Eastern States oil and gas leasehold interests
in Kentucky and West Virginia. Eastern States' interests in the 2,471 producing
wells that will be subject to and burdened by the 80% net profits interests are
referred to as the 2,471 underlying wells or the underlying wells. Eastern
States' interests in the oil and gas leases that will be subject to and burdened
by the 10% net profits interest are referred to as the underlying leases. The
underlying leases contain 1,528 proved undeveloped drilling locations. The
underlying wells and the underlying leases are collectively referred to as the
underlying properties. The underlying properties will not include any properties
or interests acquired by Eastern States on or after September 1, 1999.

The net profits interests entitle the trust to receive 80% of the net
proceeds received by Eastern States from the sale of natural gas from the
underlying wells and 10% of the net proceeds received by Eastern States from the
sale of natural gas from wells drilled on the underlying leases on or after
September 1, 1999. Net proceeds generally means cash received from the sale of
production from the underlying properties after deducting property and
production taxes, production costs, gathering and compression charges,
development costs and administrative and drilling overhead attributable to the
underlying properties. The net profits interests will be calculated separately
for Kentucky and West Virginia. The first distribution will be paid to
unitholders of record as of December 15, 1999 on or before December 25, 1999 for
the production period September 1, 1999 through September 30, 1999. For a more
complete description of the computation of net proceeds payable to the trust,
see "Computation of Net Proceeds" that begins on page 51.

Net proceeds payable to the trust depend upon production quantities, sales
prices of natural gas and costs to develop, produce, transport and market the
natural gas. If for any quarter aggregate costs should exceed gross proceeds,
the trust unitholders would not receive any cash distributions until future net
proceeds exceed the total of those excess costs, plus interest at the prime
rate. The trust will not be required to repay amounts to Eastern States;
instead, any amounts due to Eastern States will be deducted in calculating
future net proceeds payable to the trust.

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The underlying wells are characterized by a relatively high
reserve-to-production index of 21 years and a low expected production decline
rate averaging 5.5% for the initial five-year period following this offering. If
successful, Eastern States' planned development program is expected to reduce
this decline rate to an average of 3%.

Reserves in the Appalachian Basin typically have a high degree of step-out
development success, that is, as development progresses, reserves from newly
completed wells are reclassified from the proved undeveloped to the proved
developed category and additional adjacent locations are added to proved
undeveloped reserves. As a result, the amount of total proved reserves tends to
increase as development progresses.

Eastern States operates all of the 2,471 underlying wells and intends to
operate all or substantially all of the wells drilled on the underlying leases
on or after September 1, 1999. Eastern States has an average net revenue
interest of 87% and an average working interest of 97% in the properties
burdened by the trust's net profits interests. This large percentage working
interest provides for significant control over the timing and amount of
expenditures. Eastern States believes that its operation of more than 4,700
wells and 3,200 miles of gathering pipeline in Kentucky and West Virginia
provides it with regional economies of scale and a competitive advantage since
it is able to maintain low production costs relative to other producers in the
Appalachian Basin. In addition, the coordination of Eastern States' development
program in these states is facilitated by the integrated nature of its
production, pipeline and undeveloped leasehold positions.

Eastern States will market the natural gas produced from the underlying
properties and attempt to obtain the best prices available to it in the
marketplace. Generally, natural gas produced from the underlying properties will
be sold under existing contracts that have market-based pricing terms.
Currently, approximately 90% of natural gas produced by Eastern States is sold
under existing short-term contracts with its affiliate, Statoil Energy Services,
Inc., and affiliates of CNG Transmission Corp. For the eight month period ending
August 31, 1999, approximately 68% of the natural gas produced by Eastern States
was sold to Statoil Energy Services and approximately 22% was sold to affiliates
of CNG Transmission. The remaining natural gas is sold to numerous purchasers
generally at market-based prices.

Eastern States has experienced a temporary reduction in its delivery of
natural gas as a result of a shutdown of a third-party pipeline delivery system
for replacement of a portion of its pipeline system. The temporary shutdown,
which commenced September 27, 1999 and is expected to last through November 15,
1999, affects approximately 30% of Eastern States production in Kentucky, most
of which is attributable to the underlying wells. As a result of this shutdown,
the revenues attributable to the underlying wells for the fourth quarter of 1999
will be reduced, which in turn will reduce the amount of net proceeds payable to
the trust.

Eastern States has agreed, for the benefit of the trust, to hedge the sales
price payable for year 2000 production attributable to the net profits
interests. Under the hedge agreement, if the monthly closing NYMEX price in any
month of year 2000 is less than $ per MMbtu, Eastern States will pay the
trust an amount for the trust's share of that month's production based upon the
excess of $ per MMbtu over that monthly closing NYMEX price. If the monthly
closing NYMEX price in any month of the year 2000 exceeds $ per MMbtu,
Eastern States will retain from the net proceeds payable to the trust an amount
for the trust's share of that month's production based upon that excess. The
effect of this so called "collar" arrangement is that for year 2000 production
the net proceeds payable to the trust will be calculated, and the distributable
cash of the trust will be based, upon a "floor" price of $ per MMbtu and a
"ceiling" price of $ per MMbtu even if the prevailing monthly closing NYMEX
price is less than the "floor" price or more than the "ceiling" price. After the
year 2000, the price payable for production attributable to the net profits
interests will be a variable price not subject to a hedge agreement and may be
less than the $ per MMbtu "floor" price, or more than $ per MMbtu
"ceiling" price, specified under the hedge agreement.

2
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Statoil Energy is a U.S. subsidiary of the Norwegian state oil company "den
norske stats oljeselskap a.s," which is also known as The Statoil Group. As
described under the caption "Eastern States," The Statoil Group has decided to
pursue a sale of its ownership in Statoil Energy. None of The Statoil Group,
Statoil Energy or Eastern States can assure you that

- this sale will be made,

- if so made, when this sale will be made or,

- if so made, that it will not adversely affect Eastern States or its
ability to operate and develop the underlying properties as contemplated
herein.

On federal income tax returns, investors will be required to include their
proportionate share of trust net income. Investors will also be entitled to
claim a depletion deduction relating to production from the underlying
properties. Because payments to the trust will be generated by depleting assets,
a portion of each distribution may represent a return of your original
investment rather than a return on your original investment. The deductions will
permit investors to defer or reduce taxes on a significant portion of the income
recognized as a result of owning an interest in the trust.

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EASTERN STATES' OWNERSHIP INTERESTS ARE ALIGNED WITH THE UNITHOLDERS

Eastern States' retained interest in the underlying properties entitles it
to 20% of the net proceeds from the sale of production from the 2,471 underlying
wells and 90% of the net proceeds from the sale of production from wells drilled
on the underlying leases on or after September 1, 1999.

Eastern States will also own up to 25% of the outstanding trust units.
Eastern States believes that its retained direct ownership interest in the
underlying properties, as well as the retained trust units, provides it with
sufficient economic incentives to continue to operate and develop the underlying
properties in an efficient and cost-effective manner. Eastern States is under no
obligation to continue to own the underlying properties. If Eastern States
disposes of a substantial portion of these retained interests, its economic
incentive to continue to operate and develop the underlying properties would
decline.

The following chart shows the relationship of The Statoil Group, Statoil
Energy, Eastern States, the underlying properties, the trust and the public
trust unitholders, assuming no exercise of the underwriters' over-allotment
option.

CHART

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(a) The Statoil Group holds its 99.9% interest in Statoil Energy through a
wholly owned subsidiary, Statoil Energy Holdings, Inc. As described under
the caption "Eastern States," The Statoil Group has decided to pursue a sale
of its ownership in Statoil Energy.

(b) If the underwriters' over-allotment option is exercised in full,
approximately 86% of the trust units will be owned by the public unitholders
and Eastern States will retain the remaining 14% of the trust units.

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THE UNDERLYING PROPERTIES

The underlying properties are located in the Appalachian Basin, which is
the oldest and geographically one of the largest natural gas producing regions
in the United States. As of August 31, 1999, Ryder Scott estimated the proved
developed reserves of the 2,471 underlying wells to be 331 Bcfe, with future net
cash flows discounted at 10% before income taxes of approximately $265 million.
Approximately 65% of the future net discounted cash flows before income taxes
are represented by proved developed reserves located in West Virginia and
approximately 35% of the future net discounted cash flows before income taxes
are represented by proved developed reserves located in Kentucky. As of August
31, 1999, Ryder Scott estimated proved undeveloped reserves for the underlying
leases to be 437 Bcfe.

The areas in which the underlying properties are located are characterized
by wells with comparably low rates of annual decline in production, low
production costs and high Btu, or energy, content. Once drilled and completed,
wells in the Appalachian Basin typically have low ongoing operating and
maintenance requirements and minimal capital expenditures. Wells in these areas
have been producing for many years, in some cases since the early 1900's.
Reserve estimates for properties with long production histories are generally
more reliable than estimates for properties with shorter histories.

Substantially all of the underlying wells are relatively shallow, with
depths ranging from 1,000 to 7,000 feet below the surface. Many of the
underlying wells are completed in more than one producing zone and production
from these zones may be mixed or commingled. Commingled production lowers
producing costs on a per unit basis compared to isolated zone completions.

Eastern States' transfers to the trust of net profits interests in the
underlying wells in Kentucky and West Virginia are intended to create a
diversity of well profiles and a diversity of value. The well with the highest
discounted net present value in the Ryder Scott reserve report represents less
than 0.5% of the value of all underlying wells. The inclusion of a large number
of future drilling opportunities on approximately 1.2 million gross acres
comprising the underlying leases, excluding the Rome exploration area but before
giving effect to the other excluded interests described in the two paragraphs
below, along with the underlying wells will provide statistical and geological
diversity in multiple potential producing horizons in Kentucky and West
Virginia.

Eastern States currently owns approximately 4,700 producing wells in
Kentucky and West Virginia. The 2,471 producing wells that constitute the
underlying wells do not include wells in Kentucky and West Virginia with any of
the following characteristics:

- wells owned by a financial institution that are Section 29 production
payment properties and most of which are operated by Eastern States;

- wells drilled during the 20 months ended August 31, 1999, each of which
has a limited production history and a relatively high decline profile;

- wells with high operating costs;

- marginal producing wells and associated leases;

- wells and associated leases with title or consent issues; and

- wells in which Eastern States is not the operator.

The underlying leases do not include leases and interests in Kentucky and
West Virginia with any of the following characteristics:

- leases and mineral interests in Kentucky pertaining to the Rome
exploration area, which is characterized by high exploration risk;

- the portion of leases which have been farmed out to third parties; and

- leases or interests with known transfer or title issues, including all
potential coalbed methane exploration and developmental rights.

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PRODUCTION FROM THE UNDERLYING PROPERTIES RECEIVES PREMIUMS FOR LOCATION AND
HIGH ENERGY CONTENT

Natural gas produced in the Appalachian Basin has historically received a
premium over natural gas produced in other regions due to the region's close
proximity to the markets in the northeast United States. For the period 1991
through 1998, natural gas price indices for Appalachian Basin production have
averaged $0.25 per MMbtu more than prices for natural gas contracts traded on
the NYMEX for the delivery of natural gas at Henry Hub, Louisiana. During these
eight years, the average annual Appalachian Basin premium has ranged from $0.14
per MMbtu to $0.47 per MMbtu. The Appalachian Basin premium is typically lower
during warmer-than-normal winters, such as the previous two winters.

Natural gas sold from the underlying properties has historically received
an additional premium because of its higher Btu content. The average Btu content
for each cubic foot of natural gas produced from the underlying properties is
approximately 1,131, which has historically provided an average 13.1% premium
over the standard measure of 1,000 Btu per cubic foot when calculating realized
prices on a per Mcf basis.

Eastern States cannot provide any assurance that it will be able to realize
either of these premiums in the future.

LOW COST PRODUCER

Eastern States believes that it is a low cost producer. Based on the
contractual production costs to be charged by Eastern States on a per well basis
and based on the estimated production for the year 2000, Eastern States
estimates that production costs and taxes allocated to the trust in computing
net proceeds will be $0.48 per Mcfe during 2000. For public reporting companies
in the United States, the average production cost from 1996 through 1998 was
$0.61 per Mcfe. Eastern States cannot assure you that it will continue to be a
low cost producer.

LONG LIFE OF PROPERTIES

The productive lives of producing natural gas properties are often compared
using their reserve-to-production index. This index is calculated by dividing
total proved reserves of the property by annual production for the prior 12
months. The reserve-to-production index for the underlying properties at August
31, 1999 was approximately 21 years. This reserve-to-production index shows a
relatively long producing life compared to an average index of 8.8 years for
U.S. natural gas properties at year-end 1997. Because production rates naturally
decline over time, the reserve-to-production index may not be a useful estimate
of how long properties should economically produce. Based on the Ryder Scott
reserve report, production from the underlying properties is expected to
continue for at least 50 more years.

HIGH PERCENTAGE OF PROVED DEVELOPED RESERVES

Proved developed reserves are generally the lowest risk category of
reserves because their production requires no significant future development
costs and their production histories are established. Proved developed reserves
represent approximately 88% of the total proved reserves and 96% of the future
net discounted cash flow from the trust's net profits interests in the
underlying properties.

HISTORY OF LOW COST ADDITIONS TO PROVED RESERVES

Eastern States has a record of successfully adding reserves to the
underlying properties through development at costs which are generally less than
U.S. industry averages. Over the three years ended December 31, 1998, Eastern
States has added through development drilling approximately 97 Bcfe of proved
developed reserves at an average cost of $0.65 per Mcfe in Kentucky and West
Virginia. For public reporting companies in the United States, the average
industry cost of adding natural gas reserves from 1996 through 1998 was $0.76
per Mcfe. In addition, during 1997 and 1998, Eastern States had substantial
upward revisions of its proved undeveloped reserve estimates on the underlying
properties. Eastern States

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cannot assure you that it will continue to be able to add proved reserves at a
lower cost than the industry average or that it will continue to have upward
revisions of its reserve estimates.

SIGNIFICANT INVENTORY OF DRILLING OPPORTUNITIES

Eastern States currently has an inventory of approximately 1.2 million
gross acres, excluding the Rome exploration area but before giving effect to the
other excluded interests, comprising the underlying leases, of which
approximately 74% have not been developed. As of August 31, 1999, Ryder Scott
estimated the proved undeveloped reserves of the underlying leases to be 437
Bcfe from 1,528 proved undeveloped drilling locations, with estimated future net
discounted cash flows of $102 million. Based upon current conditions, Eastern
States intends to drill an average of approximately 200 wells per year on the
underlying leases for at least the next five years. The trust will have a 10%
net profits interest in these wells. The development costs for drilling 200
wells, including drilling overhead, in the year 2000 is estimated to be
approximately $44 million, of which approximately $4.4 million will be
attributable to the net profits interest of the trust. Eastern States expects to
fund its development expenditures from internally generated cash flows from
existing properties. The level of development activity and the actual costs
incurred, however, will depend on results of prior development activities,
natural gas prices and the development cost in comparison to expected rates of
return, as well as the types of wells drilled and any unanticipated events. In
the last five years, Eastern States has completed approximately 98% of the wells
it has drilled in Kentucky and West Virginia.

Eastern States may face conflicts of interest in allocating its resources
between additional development of the underlying properties and development of
other oil and natural gas properties that it now owns or may own in the future.
Eastern States allocates resources for development based on expected rates of
return. The underlying properties have historically provided attractive rates of
return on development projects compared to Eastern States' other properties and
are expected to continue to do so in the future.

EFFECT OF PLANNED DEVELOPMENT PROGRAM

Without future development, the underlying wells would typically experience
a 5.5% annual decline in production for the initial five-year period following
this offering. Projected development expenditures for the underlying properties
included in the Ryder Scott reserve report, totaling $285 million through 2007
or $28.5 million net to the trust, are expected to reduce the natural rate of
decline in production to an average of 3% per year. If Eastern States drills and
completes new wells or conducts other development activities related to the
2,471 underlying wells, those activities should serve to offset, at least in
part, the natural production decline from the underlying wells. The trust will
benefit from increased production, net of 80% of the related development costs
of the 2,471 underlying wells and net of 10% of the related development costs of
new wells drilled on or after September 1, 1999 on the underlying leases.
Eastern States' development plan will differ from that reflected in the Ryder
Scott reserve report because Eastern States typically drills a number of
unproved locations each year.

ADDITIONAL DEVELOPMENT OPPORTUNITIES

Eastern States believes that the underlying properties may offer economic
development projects that are not included in its existing proved reserves. For
the period January 1, 1998 to August 31, 1999, approximately 40% of all wells
drilled by Eastern States were on locations classified as unproved at the time
of drilling. These additional development opportunities could add production and
proved reserves beyond those contained in the Ryder Scott reserve report.

Eastern States expects costs per Mcfe associated with reserves added
through additional development projects to be comparable to its historical costs
of reserve additions in Kentucky and West Virginia. Development costs will be
deducted from the net profits interests as they are incurred and will result in
lower quarterly distributions than would exist if these costs were not incurred.
Production increases from

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these projects may ultimately increase future distributions over what would have
been distributed had the development expenditures not been incurred. These
development opportunities include:

- drilling unproved locations;

- deepening existing wells in locations or into formations that are not
classified as proved reserves in the Ryder Scott reserve report;

- opening new producing zones in existing wells;
- recompletions;
- adding pipelines and compression to improve production flow or to reduce
third party gathering and compression charges; and
- performing mechanical and chemical treatments to stimulate production
rates.

These development activities will be primarily attributable to wells
drilled on the underlying leases that are subject to the 10% net profits
interest, but could be attributable to the 2,471 underlying wells that are
subject to the 80% net profits interest. For a description on whether
development activities will be attributable to the 10% net profits interest or
the 80% net profits interest, see "The Underlying Properties -- General."

PRO FORMA OPERATING MARGIN BEFORE DEVELOPMENT COSTS

The following is a discussion of the pro forma adjustments made to the
historical average net sales meter price after deducting third party gathering
and compression charges for the underlying properties for the year ended
December 31, 1998 and the eight months ended August 31, 1999 to arrive at a pro
forma operating margin. Except for the pro forma adjustments, the quantities and
amounts in this presentation are identical to those reported in the historical
financial statements for the underlying properties. For a further description of
these costs and charges, see "Computation of Net Proceeds -- Net Profits
Interests."

Eastern States' Gathering and Compression Costs. Eastern States' gathering
and compression costs consist of the following two components shown on two lines
in the table: actual costs incurred to gather, compress and process natural gas
produced from the underlying properties and an amount to reimburse Eastern
States for depreciation of the gathering and compression facilities and to
provide a reasonable return on investment in the facilities. Eastern States' pro
forma gathering and compression charges shown in the following table are the
actual costs incurred of $0.09 per Mcfe for the year ended December 31, 1998 and
$0.09 per Mcfe for the eight months ended August 31, 1999. The table also shows
a reimbursement for depreciation and return on investment of $0.14 per Mcfe for
the year ended December 31, 1998 and of $0.14 per Mcfe for the eight months
ended August 31, 1999. The reimbursement for depreciation and return on
investment have not been allocated in the past by Eastern States and Eastern
States used the same amount in calculating projected year 2000 distributable
cash.

Compressor Fuel and Line Loss. Eastern States' compressor fuel and line
loss shown in the following table reflects actual costs of $0.14 per Mcfe for
the year ended December 31, 1998 and $0.14 per Mcfe for the eight months ended
August 31, 1999. In the future, the amount of this charge will be based on
actual volumes consumed as fuel by Eastern States' compressors and actual
volumes lost by Eastern States during gathering and compression.

Production Costs. Except for wells completed below 7,000 feet, Eastern
States will deduct a monthly fixed production fee of $170 per well for wells
producing five or more Mcf per day and $70 per well for wells producing less
than five Mcf per day. For wells completed at depths below 7,000 feet, Eastern
States will deduct a monthly fixed production fee of $300 per well regardless of
daily production amounts. These charges will also apply to shut-in wells,
temporarily abandoned wells and other inactive wells. Prior to the closing of
this offering, Eastern States had actual direct production costs of $0.19 per
Mcfe for the year ended December 31, 1998 and $0.20 per Mcfe for the eight
months ended August 31, 1999 relating to the underlying properties. The pro
forma production costs are higher than actual costs in order to provide Eastern
States a reimbursement of $0.04 to $0.05 per Mcfe for depreciation and
amortization of its office expenditures, information systems and other
capitalized costs which are included in the fixed charges.

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13

Overhead. Prior to the closing of this offering, Eastern States has not
charged an overhead fee. The pro forma overhead expense represents a monthly fee
to be charged by Eastern States of $65 per well to reimburse Eastern States for
its general and administrative costs. This fee will continue to be charged in
the event a well is shut-in, temporarily abandoned or otherwise inactive.

Development Costs. Development costs are not included in the following
table since none of the wells drilled by Eastern States in the period January 1,
1998 through August 31, 1999 are included in the underlying properties because
of their limited production history and relatively high decline profile.
Development costs, including a drilling overhead fee of $36,000 for each well
drilled or deepened to another formation, zone or horizon on the underlying
properties after September 1, 1999, will be deducted in the future as Eastern
States incurs expenses to fund development of the underlying properties. This
amount will be proportionately reduced based on Eastern States' percentage
working interest on each well drilled on underlying properties, which currently
averages 97%. Eastern States expects to drill approximately 200 wells in the
year 2000 on the underlying leases resulting in development costs of
approximately $44 million, of which approximately $4.4 million will be
attributable to the net profits interests. Based on the Ryder Scott reserve
report for estimated production in the year 2000 of 13.6 Bcfe, this equates to
development costs of $0.32 per Mcfe.

PRO FORMA
-------------------------------
YEAR ENDED EIGHT MONTHS
DECEMBER 31, ENDED AUGUST 31,
1998 1999
------------ ----------------
(PER MCFE) (PER MCFE)

Sales Price:
Average net sales meter price after deducting third
party gathering and compression charges............. $ 2.42 $ 2.36
Less Eastern States' gathering and compression
charges............................................. (0.09) (0.09)
Less pro forma reimbursement for depreciation and
return on investment................................ (0.14) (0.14)
Less Eastern States' compressor fuel cost and line
loss................................................ (0.14) (0.14)
------- -------
Pro forma average realized sales price................. 2.05 1.99
------- -------
Expenses:
Production costs....................................... 0.23 0.25
Production and property taxes.......................... 0.20 0.19
Overhead............................................... 0.10 0.10
Development costs...................................... -- --
------- -------
Total expenses................................. 0.53 0.54
------- -------
Operating margin......................................... $ 1.52 $ 1.45
======= =======

PROVED RESERVES

Based on the Ryder Scott reserve report, proved reserves of the underlying
properties are over 99% natural gas. The following tables provide, as of August
31, 1999, estimated proved reserves of natural gas and natural gas equivalents,
and undiscounted and discounted estimated future net cash flows for the
underlying properties and the net profits interests. The estimates below were
prepared by Ryder Scott. Proved reserves in the tables below for the underlying
properties are based on natural gas and oil prices realized by Eastern States as
of August 31, 1999, which were $2.75 per Mcf of natural gas and $18.75 per Bbl
of oil. Proved reserves in the table below for the net profits interest are
based on prices of $2.61 per Mcf of natural gas and $18.75 per Bbl of oil. The
$2.61 price represents the $2.75 price realized by Eastern States less the $0.14
charge to the net profits interest for reimbursement for depreciation and a
return on Eastern States' investment in its gathering and compression systems,
which has not been charged by Eastern States prior to the closing of this
offering. Natural gas equivalents in the tables are the sum of the reserves for
natural gas and oil, calculated on the basis that one Bbl of oil is the energy
equivalent of six Mcf of natural gas. These amounts exclude unproved reserves
that Eastern States may develop in the

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future. The amounts of estimated future net cash flows from proved reserves
shown in the table are before income taxes. Discounted future net revenues are
based on a discount rate of 10%. Reserve estimates are subject to revision.

PROVED DEVELOPED RESERVES OF THE UNDERLYING PROPERTIES

AS OF AUGUST 31, 1999

ESTIMATED FUTURE NET CASH
PROVED DEVELOPED RESERVES FLOWS FROM PROVED
---------------------------- DEVELOPED RESERVES
GAS EQUIVALENTS -------------------------
GAS (MMCF) (MMCFE) UNDISCOUNTED DISCOUNTED
---------- --------------- ------------ ----------
($ IN THOUSANDS)

Underlying wells by district:
Brenton, West Virginia................... 85,397 85,397 $188,642 $ 70,194
Madison, West Virginia................... 79,114 79,155 155,303 61,034
Weston, West Virginia.................... 46,904 48,333 106,569 42,273
Pikeville, Kentucky...................... 118,166 118,254 270,963 91,360
------- ------- -------- --------
Total............................ 329,581 331,139 $721,477 $264,861

PROVED UNDEVELOPED RESERVES OF THE UNDERLYING PROPERTIES

AS OF AUGUST 31, 1999

ESTIMATED FUTURE NET CASH
PROVED UNDEVELOPED RESERVES FLOWS FROM PROVED
---------------------------- UNDEVELOPED RESERVES
GAS EQUIVALENTS -------------------------
GAS (MMCF) (MMCFE) UNDISCOUNTED DISCOUNTED
---------- --------------- ------------ ----------
($ IN THOUSANDS)

Underlying leases by district:
Brenton, West Virginia................... 204,626 204,626 $350,763 $ 38,581
Madison, West Virginia................... 79,755 79,755 114,983 16,631
Weston, West Virginia.................... 11,158 11,158 17,612 1,727
Pikeville, Kentucky...................... 140,994 140,994 266,113 45,477
------- ------- -------- --------
Total............................ 436,533 436,533 $749,471 $102,416

TOTAL PROVED RESERVES OF THE UNDERLYING PROPERTIES

AS OF AUGUST 31, 1999

ESTIMATED FUTURE NET CASH
TOTAL PROVED RESERVES FLOWS FROM TOTAL PROVED
---------------------------- RESERVES
GAS EQUIVALENTS -------------------------
GAS (MMCF) (MMCFE) UNDISCOUNTED DISCOUNTED
---------- --------------- ------------ ----------
($ IN THOUSANDS)

Underlying properties by district:
Brenton, West Virginia................... 290,023 290,023 $ 539,405 $108,775
Madison, West Virginia................... 158,869 158,910 270,286 77,665
Weston, West Virginia.................... 58,062 59,491 124,181 44,000
Pikeville, Kentucky...................... 259,160 259,248 537,076 136,837
------- ------- ---------- --------
Total............................ 766,114 767,672 $1,470,948 $367,277

Proved reserves for the net profits interests attributable to the 2,471
underlying wells are calculated by subtracting from 80% of proved reserves,
reserve quantities of a sufficient value to pay 80% of the future estimated
production and development costs that are deducted in calculating net proceeds,
before overhead and trust administrative expenses. Proved reserves for the net
profits interests attributable to the proved undeveloped reserves owned by
Eastern States in Kentucky and West Virginia are calculated by subtracting from
10% of the proved undeveloped reserves, reserve quantities of a sufficient value
to pay 10% of the future estimated production and development costs that are
deducted in calculating net

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15

proceeds before overhead and trust administrative expenses. Approximately 67
Bcfe of proved reserves has been deducted to pay the future estimated production
and development costs for the underlying properties. As a result, proved
reserves for the net profits interests reflect quantities that are calculated
after reductions for future costs and expenses based on price and cost
assumptions used in the reserve estimates.

For the year 2000, production and property taxes of approximately $2.9
million have not been deducted in calculating reserve quantities attributable to
the net profits interests, but are reflected as costs in the reserve report.

For the year 2000, administrative overhead of the trust is expected to be
$1.5 million, the drilling overhead fee charged to the trust is expected to be
approximately $700,000 and trust administrative expenses are expected to be
approximately $300,000. These overhead and trust administrative expenses have
not been deducted in calculating reserve quantities attributable to the net
profits interests and are not reflected as costs in the reserve report.

PROVED RESERVES FOR THE NET PROFITS INTERESTS

AS OF AUGUST 31, 1999

ESTIMATED FUTURE NET CASH
TOTAL PROVED RESERVES FLOWS FROM TOTAL
---------------------------- PROVED RESERVES
GAS EQUIVALENTS -------------------------
GAS (MMCF) (MMCFE) UNDISCOUNTED DISCOUNTED
---------- --------------- ------------ ----------
($ IN THOUSANDS)

Underlying properties:
Net profits interests in underlying wells
(80%)...................................... 210,018 211,044 $507,436 $191,971
Net profits interests in underlying leases
(10%)...................................... 29,083 29,083 69,771 8,449
------- ------- -------- --------
Total net profits interest...................... 239,101 240,127 $577,207 $200,420
======= ======= ======== ========
Per trust unit (10,500,000 trust units)......... $ 54.97 $ 19.09
======== ========

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HISTORICAL RESULTS FROM THE UNDERLYING PROPERTIES

The following table provides production and financial information relating
to the underlying properties for 1996, 1997 and 1998 and for each of the
eight-month periods ended August 31, 1998 and 1999. Eastern States did not own
all of the underlying properties for each of the periods indicated. The audited
statements of revenue and direct operating expenses of the underlying properties
for the years ended December 31, 1996, 1997 and 1998 and the unaudited
statements for each of the eight-month periods ended August 31, 1998 and 1999
begin on page F-3 in this prospectus. This table reflects only historical costs
and does not include the incremental costs and charges that will be deducted by
Eastern States in calculating net proceeds payable to the trust.

EIGHT MONTHS
ENDED AUGUST 31,
-----------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
($ IN THOUSANDS) (UNAUDITED)

Wellhead volumes:
Natural gas (MMcf)............................ 19,318 19,960 19,040 13,184 11,967
Oil (MBbls)................................... 35.1 30.6 20.4 12.9 18.9
Average realized sales prices:
Natural gas (per Mcf)......................... $ 2.84 $ 2.62 $ 2.20 $ 2.27 $ 2.14
Oil (per Bbl)................................. $ 19.29 $ 17.35 $ 11.86 $ 12.17 $ 12.17
Revenue:
Natural gas sales............................. $54,877 $52,303 $41,835 $29,879 $25,594
Oil sales..................................... 677 531 242 157 230
------- ------- ------- ------- -------
Total................................. 55,554 52,834 42,077 30,036 25,824
------- ------- ------- ------- -------
Direct operating expenses:
Production and property taxes................. 5,179 4,872 3,809 2,713 2,338
Production expenses........................... 6,300 5,106 3,603 2,401 2,401
------- ------- ------- ------- -------
Total................................. 11,479 9,978 7,412 5,114 4,739
------- ------- ------- ------- -------
Excess of revenues over direct operating
expenses...................................... $44,075 $42,856 $34,665 $24,922 $21,085
======= ======= ======= ======= =======

YEAR 2000 PROJECTED DISTRIBUTABLE CASH

The following table provides a projection of trust distributable cash
related to estimated production for the twelve months ending December 31, 2000.
This projection assumes sales volumes and production and development costs
estimated by Ryder Scott. A copy of the Ryder Scott reserve report for the net
profits interests is included as Exhibit B to this prospectus.

The calculations in the projection assume an average net wellhead price of
$ per Mcf of natural gas for year 2000 production, which is based on the
NYMEX mid-point under the hedge agreement, and oil prices of $18.00 per Bbl.
Eastern States has prepared this projection as its best estimate of trust
distributable cash for the year 2000, on an accrual or production basis, based
on these pricing assumptions and other assumptions that are described in
"Projected Year 2000 Distributable Cash -- Significant Assumptions Used to
Prepare the Projected Year 2000 Distributable Cash." Because the projections are
prepared on an accrual or production basis for the year 2000, the projections
represent an estimate of cash that would be distributed to unitholders on or
before June 25, 2000, September 25, 2000, December 25, 2000 and March 25, 2001.
The projections and the assumptions on which they are based are subject to

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17

significant uncertainties, many of which are beyond the control of Eastern
States or the trust. ACTUAL YEAR 2000 DISTRIBUTABLE CASH, THEREFORE, COULD VARY
SIGNIFICANTLY BASED UPON CHANGES IN ANY OF THESE ASSUMPTIONS.

Distributable cash is particularly sensitive to natural gas prices. See
"Projected Year 2000 Distributable Cash -- Sensitivity of Projected Year 2000
Distributable Cash to Natural Gas Prices" which shows estimated effects on
projected year 2000 distributable cash from changes in natural gas prices.
Accordingly, the projected year 2000 distributable cash is not necessarily
indicative of distributions for future years.

As a result of typical production declines for natural gas properties, and,
subject to the success of the drilling of development wells, production
estimates generally decrease from year to year. Due to the seasonal demand for
natural gas, the amount of distributable cash may vary on a seasonal basis. Cash
available for distribution may be subject to further seasonal variation since
the weather-related adjustment of drilling activity may result in higher capital
expenditures during the warmer period of the year, when historically lower
natural gas prices are realized. For example, in the year 2000, Eastern States
expects to drill on the underlying properties approximately 15 wells in the
first quarter, approximately 55 wells in the second quarter, approximately 80
wells in the third quarter and approximately 50 wells in the fourth quarter.

PRODUCTION FROM
PRODUCTION FROM NEW WELLS ON COMBINED NET
UNDERLYING WELLS UNDERLYING LEASES PROFITS INTERESTS
---------------- ----------------- -----------------
($ IN THOUSANDS)

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PRODUCTION FROM
PRODUCTION FROM NEW WELLS ON COMBINED NET
UNDERLYING WELLS UNDERLYING LEASES PROFITS INTERESTS
---------------- ----------------- -----------------
($ IN THOUSANDS)

Calculation of Distributable Cash
Revenues:
Natural gas sales............................. $42,236 $ 13,446 $35,134
Oil sales..................................... 267 -- 213
------- -------- -------
Total.................................... $42,503 $ 13,446 $35,347
------- -------- -------
Costs:
Production and property taxes................. 3,443 1,089 2,863
Production costs.............................. 4,510 302 3,639
Development costs and drilling overhead....... -- 44,249 4,425
Overhead...................................... 1,875 115 1,511
------- -------- -------
Total.................................... 9,828 45,755 12,438
------- -------- -------
Net proceeds.................................. 32,675 (32,309) 22,909
Net profits percentage........................ 80% 10%
------- -------- -------
Trust cash.................................... 26,140 (3,231) 22,909
Trust administrative expenses................. 300
=======
Trust distributable cash...................... $22,609
=======
Trust distributable cash per trust unit
(10,500,000 trust units).................... $ 2.15
=======

CASH DISTRIBUTION AS A PERCENTAGE OF
AMOUNT $20.00 TRUST UNIT PRICE
------ ------------------------------------

Per Trust Unit (10,500,000 trust units):
Total cash distributions (and taxable income before
depletion)......................................... $2.15 10.75%
Cost depletion tax deduction.......................... (0.91)
-----
Taxable income........................................ 1.24
Income tax rate(c).................................... 39.6%
-----
Income tax to unitholders............................. (0.49)
-----
Net cash distributions after tax to unitholders....... $1.66 8.30%
=====

- ---------------

(a) The 1% facilities maintenance allowance provides for an estimated loss of
production volumes due to the periodic shutdown of gathering and
compression facilities, transmission pipelines or other production
equipment.

(b) For the adjustments made to result in an assumed average net wellhead price
of $2.59 per Mcf, see the table under the caption "Projected Year 2000
Distributable Cash" on page 27 of this prospectus.

(c) Assumes maximum federal effective tax rate applicable to individuals, but
does not take into account state income taxes that may be payable by
unitholders to Kentucky and West Virginia or their state of residence.

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19

THE OFFERING

Trust units offered by Eastern
States.......................... 7,875,000, or 9,056,250 if the underwriters'
over-allotment option is exercised in full.

Trust units outstanding......... 10,500,000 trust units will be issued and
outstanding upon the closing of this
offering, of which 2,625,000 trust units will
be owned by Eastern States. If the
underwriters' over-allotment option is
exercised in full, 1,443,750 of the trust
units will be owned by Eastern States.

Use of proceeds................. Eastern States will receive all the net
proceeds from this offering, which will be
used to repay a portion of its existing
indebtedness to Statoil Energy Holdings, Inc.

NYSE symbol..................... The trust has applied to list the trust units
on the New York Stock Exchange under the
symbol "ANG."

Sales price hedge for Year 2000
production.................... Eastern States has agreed to hedge the NYMEX
portion of the sales price payable for the
trust's share of year 2000 natural gas
production. Under this agreement, if the
monthly closing NYMEX price in any month
during year 2000 is less than a "floor" price
of $ per MMbtu or more than a "ceiling"
price of $ per MMbtu, net proceeds
payable to the trust for year 2000 gas
production will be calculated based upon the
"floor" price or "ceiling" price.

Conditional right of
repurchase...................... Eastern States will retain the right to
repurchase all, but not less than all, of the
outstanding units at any time if 15% or less
of the outstanding units are owned by persons
or entities other than Eastern States and its
affiliates. These repurchases will be made at
no less than the current market price.

Property trustee................ Bank One, Texas, N.A.

Delaware trustee................ Bank One Delaware, Inc.

INVESTING IN TRUST UNITS

Investing in the trust units differs from investing in corporate stock in
the following ways:

- trust unitholders are not owed a fiduciary duty by Eastern States, but
they are owed a fiduciary duty by the trustees of the trusts to the
extent provided in the trust agreement;

- trust unitholders have limited voting rights;
- trust unitholders are taxed directly on their proportionate share of
trust net income;
- trust unitholders are entitled to federal income tax depletion
deductions;
- substantially all trust cash must be distributed to trust unitholders;
and
- trust assets are limited to the net profits interests which have a finite
economic life.

RISK FACTORS

Before investing in trust units, you should carefully consider the matters
described under "Risk Factors" beginning on page 16 of this prospectus.

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20

RISK FACTORS

RISKS ASSOCIATED WITH THE NATURAL GAS INDUSTRY AND THE UNDERLYING PROPERTIES

NATURAL GAS PRICE DECLINES AND MARKET VOLATILITY COULD RESULT IN LOWER CASH
DISTRIBUTIONS TO TRUST UNITHOLDERS.

The trust's revenues and quarterly cash distributions are highly dependent
upon the prices realized from the sale of natural gas. A material decrease in
the prices realized from the sale of natural gas by Eastern States could reduce
the amount of cash distributions paid to unitholders. Lower natural gas prices
may reduce the amount of natural gas that is economic to produce and reduce net
proceeds available to the trust. The volatility of energy prices reduces the
accuracy of estimates of future cash distributions to trust unitholders. Natural
gas prices can fluctuate widely on a month-to-month basis in response to a
variety of factors that are beyond the control of the trust and Eastern States.
These factors include, among others:

- weather conditions, primarily in the northeast United States;

- the supply and price of domestic and foreign natural gas and oil;
- delivery interruptions by upstream pipeline companies;
- the level of demand;

- worldwide economic and political conditions;

- the price and availability of alternative fuels;
- environmental regulations; and
- worldwide energy conservation measures.

Moreover, government regulations, such as regulation of natural gas
transportation or price controls, if imposed, could affect product prices in the
long term.

Also, any material decrease in the average premium received for Appalachian
Basin production could have an adverse impact on the proceeds received from the
sale of natural gas by Eastern States, resulting in lower cash distributions to
trust unitholders.

Eastern States has agreed to hedge the price paid for the trust's share of
year 2000 natural gas production. As a result of this hedging arrangement, to
the extent that the actual monthly closing NYMEX price for any month during year
2000 exceeds $ per MMbtu, Eastern States will retain all that excess. In
addition, Eastern States will not enter into any hedge agreement for the trust's
share of production from the underlying properties for any production in any
period other than year 2000.

TRUST DISTRIBUTIONS ARE AFFECTED BY COSTS AND CHARGES DEDUCTED BY EASTERN
STATES IN CALCULATING NET PROCEEDS.

Production and development costs, gathering and compression charges and
overhead fees on the underlying properties are deducted in the calculation of
the trust's share of net proceeds. Accordingly, higher or lower production and
development costs, gathering and compression charges or overhead fees will
directly decrease or increase the amount received by the trust for its net
profits interests. Property and production and other taxes are also deducted.
The charges imposed by Eastern States for production costs and both
administrative and drilling overhead fee will adjust each year beginning April
1, 2001 in accordance with an industry standard set forth in the accounting
procedures in the transfer documents or conveyances.

Because of the limited number of interstate pipeline transmission systems
available in the Appalachian Basin as well as the difficult surface topography,
producers such as Eastern States must make significant investments in pipeline
systems to gather natural gas from each well drilled. In addition, Eastern
States must have extensive compression facilities to achieve sufficient line
pressure to produce into interstate transmission pipelines. To sustain its
development drilling program, Eastern States will have to make continuing
investments in these gathering and compression facilities. Eastern States will
deduct from

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21

gross proceeds a charge for gathering, compression and processing conducted
using Eastern States' facilities, which charge will include an amount to
reimburse Eastern States for the costs of these services, plus a reimbursement
for depreciation of the facilities and a return on its investment in these
facilities. Large investments in gathering and compression facilities in the
future could decrease the amounts received by the trust for its net profits
interests.

The development costs attributable to the net profits interest in the
underlying leases will be 10% of the development costs incurred by Eastern
States to drill wells in the future. Eastern States currently anticipates
drilling an average of approximately 200 wells per year on the underlying leases
for at least the next five years. The effect of drilling these new wells will be
to reduce the amount of net proceeds received by the trust in the near term,
which will in turn reduce cash available for distribution by the trust to its
unitholders. The amount of net proceeds may fluctuate seasonally as a result of
the weather-related increase of drilling activity in the warmer months of each
year. The purpose of development drilling is to increase production over levels
that would be achieved in the absence of these expenditures.

If the net proceeds from the underlying properties located in a particular
state are less than zero for any quarter, the trust will not receive net
proceeds from those properties until future proceeds from production in that
state exceed the total of the excess costs plus accrued interest during the
deficit period. Development activities may not generate sufficient additional
revenue to repay the costs.

PROVED RESERVE ESTIMATES ATTRIBUTABLE TO THE TRUST ARE UNCERTAIN.

The value of the trust units will depend upon, among other things, the
reserves attributable to the trust's net profits interests. The calculations of
proved reserves included in this prospectus are only estimates. These estimates
were prepared by Ryder Scott. The accuracy of any reserve estimate is a function
of the quality of available data, engineering and geological interpretation and
judgment, and the assumptions used regarding quantities of recoverable natural
gas and natural gas prices. Petroleum engineers consider many factors and make
many assumptions in estimating reserves. Those factors and assumptions include:

- historical production from the area compared with production rates from
other producing areas;
- the availability of pipeline delivery systems;
- the effects of governmental regulation; and
- assumptions about future commodity prices, production and development
costs, and severance and property taxes.

Changes in these assumptions can materially change reserve estimates.
Ultimately, actual production, revenues and expenditures for the underlying
properties will vary from estimates and those variations could be material.

The trust's reserve quantities and revenues are based on estimates of
reserves and revenues for the underlying properties. The method of allocating a
portion of those reserves to the trust is complicated because the trust holds an
interest in net profits and does not own a specific percentage of the natural
gas reserves. See "The Underlying Properties -- Reserves" for a discussion of
the method of allocating proved reserves to the trust.

WEATHER CONDITIONS MAY ADVERSELY AFFECT THE DEMAND FOR AND PRICES PAID FOR
NATURAL GAS.

Generally, natural gas prices in the Appalachian Basin tend to be higher
during the first and fourth quarters of the calendar year because a large
percentage of the usage is for heating purposes. As a result, warmer than normal
winter temperatures, particularly in the northeast United States, can
significantly decrease the demand for natural gas and consequently reduce prices
available in the marketplace. Also, warmer than normal winter temperatures will
generally decrease the amount of the Appalachian Basin premium, as occurred in
the winter of 1998/1999 when the Appalachian Basin premium realized by Eastern
States averaged $0.15 per MMbtu compared to an average of $0.36 per MMbtu for
the seven

17
22

winter periods from 1990/1991 through 1997/1998. The result of these conditions
could decrease the amounts received by the trust for its net profits interests.

INTERRUPTIONS ON THIRD PARTY PIPELINE DELIVERY SYSTEMS COULD REDUCE THE
DELIVERY OF NATURAL GAS PRODUCED FROM THE UNDERLYING PROPERTIES.

Eastern States depends on the availability of third party pipeline delivery
systems to transport over 90% of its natural gas. Any interruptions in the
availability of these systems due to facilities maintenance requirements or
other extraordinary events could inhibit the ability of Eastern States to sell
its natural gas. For example, Columbia Transmission has shut down one of its
pipelines in Kentucky from September 27, 1999 through November 15, 1999 for
replacement of a portion of its pipeline system. This temporary shut-down will
delay the delivery and sale of approximately 30% of Eastern States, natural gas
production in Kentucky, most of which is attributable to the underlying
properties. As a result of this shutdown, the revenues attributable to the
underlying wells for the month of September 1999 and the fourth quarter of 1999
will be reduced, which in turn will reduce the amount of net proceeds payable to
the trust. These interruptions could, therefore, decrease the amount of net
proceeds payable the trust.

RISKS ASSOCIATED WITH THE TRUST UNITS

NET PROCEEDS ARE DERIVED FROM THE SALE OF DEPLETING ASSETS.

The net proceeds payable to the trust are derived from the sale of
depleting assets. The reduction in proved reserve quantities is a common measure
of depletion. Future maintenance and development projects on the underlying
properties will affect the quantity of proved reserves and can offset the
reduction in proved reserves. The timing and size of these projects will depend
on the market prices of natural gas. If Eastern States, as operator of all of
the underlying properties, does not implement additional maintenance and
development projects, the future rate of production decline of proved reserves
may be higher than the rate currently expected by Eastern States.

Because net proceeds are derived from the sale of depleting assets, the
portion of distributions to trust unitholders attributable to depletion may be
considered a return of capital as opposed to a return on investment.
Distributions that are a return on capital will ultimately diminish the
depletion tax benefits available to the trust unitholders, which could reduce
the market price of the trust units over time.

THERE ARE RISKS INHERENT IN DRILLING NEW WELLS ON THE UNDERLYING LEASES.

Eastern States anticipates drilling an average of approximately 200 new
wells per year on the underlying leases for at least the next five years. No
assurance can be given that any new wells will be successful or produce in
commercial quantities or that the number of wells which are projected to be
drilled will actually be drilled. The failure of new wells in Kentucky and West
Virginia to produce in commercial quantities could cause the annual decline in
production from the underlying properties to exceed 3% per year.

PRODUCTION RISKS CAN ADVERSELY AFFECT TRUST DISTRIBUTIONS.

The occurrence of drilling, production or transportation accidents at any
of the underlying properties will reduce trust distributions by the amount of
uninsured costs. These accidents may result in personal injuries, property
damage, damage to productive formations or equipment and environmental damages.
Any of these types of costs would be deducted in calculating net proceeds
payable to the trust.

Eastern States insures against some, but not all, of the hazards associated
with the natural gas industry. For example, it is not insured against the
following hazards:

- fines and penalties;

- pollution events occurring prior to Eastern States' acquisition date of
the properties;

- professional errors and omissions of engineers, geologists and surveyors;

- loss or unrecoverability of oil and natural gas reserves;

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23

- loss of downhole equipment;

- loss of income due to third party failure to provide equipment or
materials; and

- war and associated events of civil unrest.

As a result, Eastern States may become subject to liabilities or losses that
could be substantial due to uninsured events.

THE TRUST DOES NOT CONTROL OPERATIONS AND DEVELOPMENT OF THE UNDERLYING
PROPERTIES.

Neither the trustee nor the trust unitholders can influence or control the
operation or future development of the underlying properties. Eastern States as
operator of all of the underlying properties is under no obligation to continue
operating the properties. Eastern States can sell any of the underlying
properties or relinquish its ability to control or influence operations. Neither
the trustee nor trust unitholders have the right to replace an operator.

EASTERN STATES MAY TRANSFER OR ABANDON THE UNDERLYING PROPERTIES.

Eastern States may at any time transfer all or part of the underlying
properties to another party. Unitholders will not be entitled to vote on any
transfer, and the trust will not receive any proceeds of the transfer. Following
any material transfer, the underlying properties will continue to be subject to
the net profits interests of the trust, but the net proceeds from the
transferred property would be calculated separately and paid by the transferee.
The transferee would be responsible for all of Eastern States' obligations
relating to the net profits interests on the portion of the underlying
properties transferred, and Eastern States would have no continuing obligation
to the trust for those properties. A transferee of the underlying properties, by
virtue of the transfer, may be obligated to file reports under the Securities
Exchange Act of 1934.

Eastern States or any transferee may abandon any well or property,
including the associated leases, if it reasonably believes that the well or
property is not capable of producing or continuing production in quantities
sufficient to justify further completion, development or operating expenditures,
referred to as commercially economic quantities. Abandonment of a well could
result in termination of the net profits interest relating to the abandoned
well. For a further description of Eastern States' rights to abandon a well, see
"The Underlying Properties -- Sale and Abandonment of Underlying Properties;
Sale of Net Profits Interests."

NET PROFITS INTERESTS CAN BE SOLD OR THE TRUST MAY BE TERMINATED.

The trustee must sell the net profits interests if the holders of 66 2/3%
or more of the trust units approve the sale or vote to terminate the trust. The
trustee must also sell all the net profits interests in both states if the
annual net proceeds from the underlying properties are less than $3.5 million in
Kentucky for any two consecutive years after the year 2000 or less than $3.5
million in West Virginia for any two consecutive years after the year 2000. The
sale of all the net profits interests will terminate the trust. The net proceeds
from the sale of the trust's net profits interests will be distributed to the
trust unitholders.

EASTERN STATES' CONDITIONAL RIGHT OF REPURCHASE MAY FORCE INVESTORS TO SELL
THEIR TRUST UNITS AT AN UNDESIRABLE TIME AND PRICE.

Eastern States will retain the right to repurchase all, but not less than
all, outstanding units at any time at which 15% or less of the outstanding units
are owned by persons or entities other than Eastern States and its affiliates.
These repurchases will be made at no less than the current market price. Because
of this right, investors may be forced to sell their trust units at a time and
price that is undesirable to them.

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EASTERN STATES' DISPOSAL OF TRUST UNITS MAY REDUCE THE MARKET PRICE FOR TRUST
UNITS.

At the completion of the offering, Eastern States will own 2,625,000 trust
units assuming the underwriters' over-allotment option is not exercised. If the
underwriters' over-allotment option is exercised in full, Eastern States will
own 1,443,750 trust units. It may use some or all of the trust units it owns for
a number of corporate purposes, including:

- selling them for cash; and
- exchanging them for interests in oil and natural gas properties or
securities of oil and natural gas companies.

If Eastern States sells these trust units or exchanges trust units in
connection with acquisitions, then additional trust units will be available for
sale in the market, which could result in a reduction in the market price of the
trust units. Except for the limitation on selling trust units within 180 days
following the date of this prospectus as discussed in "Underwriting," Eastern
States is not obligated to maintain a minimum number of trust units. Eastern
States' intentions will vary with market conditions.

EASTERN STATES MAY ENTER INTO CONTRACTS OR RECEIVE PAYMENTS THAT ARE NOT
NEGOTIATED IN ARM'S-LENGTH TRANSACTIONS.

Eastern States and some of its affiliates receive payments for services
relating to the underlying properties. Since the amounts to be paid to Eastern
States for these services were not negotiated at arm's-length, they may exceed
amounts that would be incurred for services from an unrelated third party.
Payments to Eastern States and its affiliates will be deducted in determining
net proceeds payable to the trust. This will reduce the amounts available for
distribution to the trust unitholders. When calculating net proceeds from the
underlying properties, the following will be deducted by Eastern States:

- a fixed production fee for each well, including shut-in wells,
temporarily abandoned wells and other inactive wells, calculated as
follows:

1. a rate per well, except for wells completed below 7,000 feet, of $170
per month for those wells producing five or more Mcfe per day on an
annual basis; or

2. a rate per well, except for wells completed below 7,000 feet, of $70
per month for those wells producing less than five Mcfe per day on an
annual basis; or

3. a rate per well of $300 per month for those wells completed in a zone
below 7,000 feet;

subject in each case to an annual adjustment beginning April 1, 2001 in
accordance with an industry standard set forth in the accounting procedures
in the transfer documents;

- development costs, including a drilling overhead fee of $36,000 for each
well drilled or deepened to another formation, zone or horizon on the
underlying properties on or after September 1, 1999, subject to an annual
adjustment beginning April 1, 2001 in accordance with an industry
standard set forth in the accounting procedures in the transfer
documents;

- Eastern States' charges to gather and compress the natural gas at actual
cost, plus reimbursement for depreciation and to provide a return on
investment of its gathering and compression systems based on a per Mcfe
gathered basis; and

- a fixed overhead fee per well of $65 per month, including shut-in wells,
temporarily abandoned wells and other inactive wells, subject to an
annual adjustment beginning April 1, 2001 in accordance with an industry
standard set forth in the accounting procedures in the transfer
documents, including engineering, accounting and administrative
functions.

In addition, Eastern States typically sells a portion of the production
from the underlying properties to its affiliate, Statoil Energy Services, at
market-based prices. Eastern States intends to continue to do so in the future,
to the extent the terms available from Statoil Energy Services are acceptable.
In 1998, approximately 68% of Eastern States' natural gas production was sold to
Statoil Energy Services. Even if

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25

Eastern States considers such terms acceptable, however, Eastern States cannot
assure you that such terms will be as good as, or exceed, those available from
unrelated third parties. For a description of our current contract with Statoil
Energy Services, see "The Underlying Properties -- Gas Purchase Contracts."

EASTERN STATES MAY HAVE INTERESTS THAT ARE DIFFERENT FROM YOURS.

Because Eastern States has interests in natural gas properties in the
Appalachian Basin that are not included in the underlying properties, Eastern
States may have interests that are different from yours. For example,

- in setting budgets for development and production expenditures for
Eastern States' properties, including the underlying properties, Eastern
States may make decisions that could adversely affect future production
from the underlying properties. These decisions could include reducing
development expenditures on the underlying properties, which could cause
natural gas production to decline at a faster rate and ultimately result
in lower future trust distributions;

- Eastern States could continue to operate an underlying property and
continue to earn an overhead fee even though abandonment of the property
might result in more net proceeds being available to trust unitholders;
and

- Eastern States could decide to sell or abandon some or all of the
underlying properties, and that decision may not be in the best interests
of the trust unitholders. For example, Eastern States might sell some or
all of the underlying properties to a third party who could reduce
development expenditures on those properties, or Eastern States might
abandon a marginal well that otherwise would continue to produce a net
profit to the trust.

Except for specified matters that require approval of the trust unitholders
described in "Description of the Trust Agreement," the documents governing the
trust do not provide a mechanism for resolving these conflicting interests.

TRUST UNITHOLDERS WILL HAVE LIMITED VOTING RIGHTS AND NO ABILITY TO INFLUENCE
OPERATIONS OF THE UNDERLYING PROPERTIES.

Your voting rights as a trust unitholder are more limited than those of
stockholders of most public corporations. For example, there is no requirement
for annual meetings of trust unitholders or for an annual or other periodic
re-election of the trustee. Additionally, trust unitholders have no voting
rights in Eastern States and therefore will have no ability to influence its
operation and development of the underlying properties.

TRUST UNITHOLDERS WILL HAVE LIMITED ABILITY TO ENFORCE RIGHTS AGAINST EASTERN
STATES.

The trust agreement and related trust law permit the trustee and the trust
to sue Eastern States or any other future owner of the underlying properties to
honor the net profits interests. If the trustee does not take the actions that
you consider appropriate to enforce provisions of the trust agreement and the
trust laws of the State of Delaware, your recourse as a trust unitholder would
likely be limited to bringing a lawsuit against the trustee to compel the
trustee to enforce the provisions of the trust agreement. You probably would not
be able to sue Eastern States or any future owner of the underlying properties.

COURTS IN SOME JURISDICTIONS MAY NOT GIVE EFFECT TO THE SAME LIMITED LIABILITY
OF TRUST UNITHOLDERS THAT IS RECOGNIZED UNDER DELAWARE LAW; THEREFORE, TRUST
UNITHOLDERS COULD HAVE PERSONAL LIABILITY FOR THE TRUST'S LIABILITIES.

Consistent with Delaware law, the trust agreement provides that the trust
unitholders will have the same limitation on liability as is accorded under the
laws of Delaware to stockholders of a corporation for profit. No assurance can
be given, however, that the courts in jurisdictions outside of Delaware will
give effect to this limitation.

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EASTERN STATES' LIABILITY TO THE TRUST IS LIMITED.

The instruments by which the net profits interests are transferred to the
trust provide that Eastern States will not be liable to the trust for performing
its duties in operating the underlying properties as long as it acts in good
faith. As a result, damage to a reservoir from drilling operations, delays in
drilling, completing, reworking or selling production from a well or failure to
enter into a gas sales contract with a particular buyer on favorable terms, and
other similar events, will not subject Eastern States to liability to trust
unitholders so long as its actions were taken in good faith.

THERE ARE RISKS ASSOCIATED WITH THE FINANCIAL CONDITION OF EASTERN STATES AND
ITS AFFILIATES.

Eastern States is engaged primarily in the exploration, development,
production, transportation and marketing of natural gas in the Appalachian
Basin. The ability of Eastern States to operate the underlying properties in a
manner to generate net profits to the trust will be dependent upon its future
financial condition and economic performance, which in turn will depend upon the
supply and demand for natural gas, prevailing economic conditions and other
factors that are beyond the control of Eastern States.

From time to time, Eastern States may enter into hedging contracts for some
of its natural gas production at specified prices for a period of time. Any
gains or losses from hedging activities will not affect amounts paid to the
trust, but large losses under these hedging contracts could have an adverse
impact on the financial condition of Eastern States.

An affiliate of Eastern States, Statoil Energy Services, Inc., currently
purchases approximately 65% of the natural gas produced by Eastern States
pursuant to an existing contract. The ability of Statoil Energy Services to
perform its obligations under the contract will be dependent upon its future
financial condition and economic performance, which in turn will depend upon the
supply and demand for natural gas, prevailing economic conditions and upon
financial, business and other factors beyond the control of Eastern States and
Statoil Energy Services.

AN IRS RULING WILL NOT BE REQUESTED BY EASTERN STATES.

The trust has received an opinion of tax counsel that the trust is a
"grantor trust" for federal income tax purposes. This means that:

- the trust will not be taxed as a corporation;
- you will be taxed directly on your pro rata share of the net income of
the trust, regardless of whether all of that net income is distributed to
you; and
- you will be allowed depletion deductions equal to the greater of
percentage depletion or cost depletion, computed on the tax basis of your
trust units, and your pro rata share of other deductions of the trust.

For a discussion of the material federal income tax consequences of the
ownership and sale of the trust units, see "Federal Income Tax Consequences"
beginning on page 54.

Tax counsel believes that its opinion is in accordance with the present
position of the IRS regarding grantor trusts. Neither Eastern States nor the
property trustee has requested a ruling from the IRS regarding these tax
questions. Neither Eastern States nor the property trustee can assure you that
they would be granted a ruling if requested or that the IRS will continue this
position in the future.

Trust unitholders should be aware of possible state tax implications of
owning trust units. For a brief summary of the material state tax considerations
affecting the trust and trust unitholders, see "State Tax Considerations"
beginning on page 58.

THE TRUST'S NET PROFITS INTERESTS MAY NOT BE RESPECTED IN A BANKRUPTCY
PROCEEDING.

Eastern States believes that the net profits interests should constitute
real property interests under Kentucky law, and a transferable economic interest
under West Virginia law. Approximately 78% of the

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gross acreage that is burdened by the net profits interests is located in West
Virginia. If during the term of the trust Eastern States or any successor owner
of the underlying properties should become a debtor in a bankruptcy proceeding,
it is not entirely clear that the net profits interests would be treated as real
property interests under the laws of Kentucky, or as a transferable economic
interest under West Virginia law. If a determination were made in a bankruptcy
proceeding that a net profits interest did not constitute a real property
interest or a transferable economic interest under applicable state law, it
could be designated an executory contract. An executory contract is a term used,
but not defined, in the federal bankruptcy code to refer to a contract under
which the obligations of both the debtor and the other party are so unsatisfied
that the failure of either to complete performance would constitute a material
breach excusing performance by the other. If a net profits interest were
designated an executory contract and rejected in the bankruptcy proceeding,
Eastern States would not be required to perform its obligations under the net
profits interest and the trust would seek damages as one of Eastern States's
unsecured creditors.

FORWARD-LOOKING STATEMENTS

Some statements made by Eastern States in this prospectus under "Projected
Year 2000 Distributable Cash," statements pertaining to future development
activities and costs and other statements contained in this prospectus are
prospective and constitute forward-looking statements. These forward-looking
statements are based on Eastern States' current projections and estimates and
are identified by words such as "expects," "intends," "plans," "projects,"
"anticipates," "believes," "estimates" and similar words. These forward-looking
statements are not guarantees of future performance and involve known and
unknown risks, uncertainties and other factors that could cause actual results
to differ materially from future results expressed or implied by the
forward-looking statements. The most significant risks, uncertainties and other
factors are discussed under "Risk Factors" above.

Among the factors that could cause actual results to differ materially are:

- natural gas price fluctuations;
- the availability of funds for future development programs;
- the results of the planned development program;
- potential delays or failure to achieve expected production from the
underlying properties;
- potential disruption of operations because of our failure or the failure
of others with whom we have material relationships to achieve timely Year
2000 compliance; and
- potential liability resulting from litigation.

In addition, these forward-looking statements may be affected by general
domestic and international economic and political conditions.

USE OF PROCEEDS

Eastern States will receive all proceeds from the sale of trust units after
deducting underwriting discounts and expenses of the offering paid by Eastern
States. The trust will not receive any proceeds from the sale of the trust
units. The net proceeds before deducting expenses will be approximately $146.5
million, and will increase to approximately $168.4 million if the underwriters
exercise their over-allotment option in full, assuming an initial public
offering price of $20.00 per trust unit. Eastern States intends to use the net
proceeds from the offering to repay a portion of the outstanding indebtedness
owed to Statoil Energy Holdings, Inc. At September 30, 1999, Eastern States'
outstanding indebtedness under the promissory note with Statoil Energy Holdings
was $505.5 million. This promissory note has an 8% annual rate of interest.

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EASTERN STATES

Eastern States, a corporation organized in Delaware, is an independent
energy company engaged in the development, production, acquisition, marketing,
gathering and transportation of natural gas and oil in the Appalachian Basin.
Eastern States is the largest owner of proved natural gas reserves in the
Appalachian Basin. Substantially all of Eastern States' natural gas and oil
reserves are located in Kentucky, Ohio, Virginia and West Virginia.

For the years ended December 31, 1996, 1997 and 1998, Eastern States had
total revenue of $18.2 million, $65.4 million and $104.7 million, and for the
first six months of 1999, Eastern States had total revenue of $57.7 million. For
the years ended December 31, 1996, 1997 and 1998, Eastern States had net income
of $3.9 million, $9.2 million and $8.3 million, and for the first six months of
1999, Eastern States had net income of $6.0 million.

Eastern States currently owns and operates over 5,700 wells in the
Appalachian Basin. At December 31, 1998, Eastern States' estimated net proved
reserves were 1,062 Bcfe, of which 709 Bcfe, or 67%, were proved developed. The
estimated discounted future net cash flows of Eastern States' proved reserves
before United States income taxes were $675 million as of December 31, 1998. For
the six months ended June 30, 1999, total average net sales meter natural gas
and oil production was 104 MMcfe per day, 98% of which was natural gas.

Eastern States is continually evaluating oil and natural gas properties and
other investment opportunities in addition to its development and operations of
existing properties, including the underlying properties.

Eastern States is an indirect wholly owned subsidiary of Statoil Energy.
Statoil Energy also:

- owns and operates power plants throughout the northeast and the
mid-Atlantic region;

- is a leading trader of wholesale electricity and natural gas; and
- specializes in providing a broad range of energy and risk management
services involving the delivery of natural gas, electricity and
alternative fuels to large industrial, institutional and commercial
customers.

- through its indirect wholly owned subsidiary, Eastern States Exploration
Company, owns and operates approximately 600 wells in Pennsylvania, with
estimated net proved reserves of 39 Bcfe at December 31, 1998 and an
average net daily sales meter production of 6 MMcfe for the six months
ended June 30, 1999. Eastern States does not own any interest in Eastern
States Exploration Company.

Statoil Energy is currently an indirect, wholly owned subsidiary of The
Statoil Group. The Statoil Group has substantial ongoing commitments associated
with various development projects worldwide and has numerous international
investment opportunities competing for limited capital. Based upon those capital
commitments, various assets and interests, including Statoil Energy, were
evaluated for strategic ranking, possible sale or joint venture. Based upon that
evaluation, The Statoil Group concluded that it was unable to continue to fund
Statoil Energy's planned increase of the scale of its operations and targeted it
for a possible joint venture.

The Statoil Group retained an investment banking firm, Credit Suisse First
Boston, early in 1999 to implement The Statoil Group's strategy with respect to
Statoil Energy. These activities initially focused on a search for a 50%
strategic partner to obtain and combine complementary assets and activities to
pursue business opportunities in the sector of the U.S. energy market not
regulated by the FERC. Based upon the results of its efforts to pursue this
joint venture strategy, The Statoil Group and its financial advisor concluded
that prospective partners, primarily utility companies, were not interested in
sharing the corporate governance and capital requirements of Statoil Energy. As
a result, on October 13, 1999 The Statoil Group announced that it plans to sell
its equity ownership in Statoil Energy and has initiated discussions with
several companies in that regard.

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None of The Statoil Group, Statoil Energy or Eastern States can provide
assurance that such a sale will be made or when such a sale might be concluded.
While The Statoil Group is currently exploring the possible sale of Statoil
Energy and its subsidiaries, including Eastern States, The Statoil Group may
determine that the sale of individual assets or divisions, including Eastern
States, is more appropriate. If a sale of Statoil Energy or Eastern States is
made, there is no assurance that it would not adversely affect Eastern States or
its ability to operate and develop the underlying properties as contemplated
herein. However, any successor to Eastern States would be subject to the
obligations of Eastern States under the transfer documents and the Trust
Agreement.

After the closing of this offering, Eastern States will continue to own and
operate the underlying properties from which the net profits interests were
conveyed. For additional information regarding Eastern States, see "Information
About Eastern States Oil & Gas, Inc.," beginning on page A-1. PURCHASERS OF
TRUST UNITS WILL NOT ACQUIRE INTERESTS IN OR OBLIGATIONS OF EASTERN STATES,
STATOIL ENERGY OR THE STATOIL GROUP. NONE OF EASTERN STATES, STATOIL ENERGY OR
THE STATOIL GROUP OWES ANY FIDUCIARY DUTY TO THE TRUST UNITHOLDERS.

THE TRUST

The trust was formed in August 1999 under the Delaware Business Trust Act
by the filing of a certificate of trust with the Delaware Secretary of State.
The trust has a property trustee, Bank One, Texas, N.A. and a Delaware trustee,
Bank One Delaware, Inc. The day-to-day operations of the trust will be managed
by a vice president and other officers of the property trustee's Corporate Trust
Administration Department. The Delaware Trustee will have only minimal rights
and duties as necessary to satisfy the requirements of the Delaware Business
Trust Act. At the closing of this offering, the trust agreement will be amended
and restated and will contain the material terms described in "Description of
the Trust Agreement." Effective September 1, 1999, Eastern States will convey
the net profits interests to the trust in exchange for all of the trust units.

The trustee can authorize the trust to borrow money to pay trust
administrative or incidental expenses that exceed cash held by the trust. The
property trustee may authorize the trust to borrow from the property trustee as
a lender. Because the property trustee is a fiduciary, the terms of the loan
must be fair to the trust unitholders. The property trustee may also deposit
funds awaiting distribution in an account with itself, if the interest paid to
the trust at least equals amounts paid by the property trustee on similar
deposits.

The trust will pay the trustees a fee of 0.20% of trust cash, before
administrative expenses, per year, which is estimated to be approximately
$45,800 for the year 2000, and a fee of $7,500 for services to terminate the
trust. The trust will also incur legal, accounting and engineering fees,
printing costs and other expenses that will be deducted from the net proceeds
received by the trust before distributions are made to trust unitholders. Total
administrative expenses of the trust are expected to be approximately $300,000
for the year 2000.

PROJECTED YEAR 2000 DISTRIBUTABLE CASH

The net profits interests will be created through two transfer documents to
the trust of Eastern States' interests in the 2,471 underlying wells and all
wells drilled on the underlying leases on or after September 1, 1999. The net
profits interests entitle the trust to receive 80% of the net proceeds received
by Eastern States from the sale of natural gas from the underlying wells and 10%
of the net proceeds received by Eastern States from the sale of natural gas
produced by wells drilled on or after September 1, 1999 on the underlying
leases. Net proceeds equals the gross proceeds received by Eastern States from
the sale of production from the underlying properties less property and
production taxes, production costs, gathering and compression charges,
development costs and administrative and drilling overhead attributable to the
underlying properties. For a more detailed description of net proceeds, see
"Computation of Net Proceeds" on page 51 of this prospectus.

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The amount of trust revenues and cash distributions to trust unitholders
will depend on:

- natural gas prices;
- the volume of natural gas produced and sold;
- the ability of Eastern States to successfully complete wells drilled
after the offering; and
- production, development and other costs.

PROJECTED YEAR 2000 DISTRIBUTABLE CASH

The following table provides a projection of distributable cash related to
the production for the 12 months ending December 31, 2000. This projection
assumes sales volumes and production and development costs estimated by Ryder
Scott. A copy of the Ryder Scott reserve report for the net profits interest is
included as Exhibit B to this prospectus.

Generally, Eastern States sells the natural gas from the underlying
properties under existing contracts that have market-based pricing terms. For
the year 2000, Eastern States has entered into a hedge agreement for the benefit
of the trust. Under this hedge agreement, which is often referred to as a
"collar" arrangement, Eastern States has agreed that if the final monthly
closing NYMEX price for natural gas in any month during year 2000 is less than
$ per MMbtu or more than $ per MMbtu, then Eastern States will calculate
the net proceeds payable to the trust for gas produced during that month based
upon the $ per MMbtu "floor" price or the $ per MMbtu "ceiling" price,
respectively. The calculations in the projections assume a weighted average
NYMEX sales price for year 2000 of $ per MMbtu, which is the mid-point of
the hedge agreement. After the year 2000, the price payable for production
attributable to the net profits interests will be a variable price not subject
to a hedge agreement and may be less than the $ per MMbtu "floor" price, or
more than $ per MMbtu "ceiling" price, specified under the hedge agreement.

The assumed NYMEX price of $2.50 per Mmbtu was then increased by an
Appalachian Basin premium of $0.28 per MMbtu and a Btu adjustment of $0.36 per
MMbtu based on an average Btu content of 1,131 per cubic foot and reduced for
third party gathering and compression charges of $0.16 per Mcf, a 5.4%
compressor fuel and line loss charge by Eastern States of $0.16 per Mcf and
Eastern States' gathering and compression charge of $0.23 per Mcf, resulting in
an average net wellhead price of $2.59 per Mcf of natural gas. Oil prices of
$18.00 per Bbl were also assumed.

Eastern States has prepared this projection as its best estimate of trust
distributable cash for the year 2000, on an accrual or production basis, based
on these pricing assumptions and other assumptions that are described in
"-- Significant Assumptions Used to Prepare the Projected Year 2000
Distributable Cash." Because the projections are prepared on an accrual or
production basis for calendar year 2000, the projections represent an estimate
of cash that would be distributed to unitholders on or about June 25, 2000,
September 25, 2000, December 25, 2000 and March 25, 2001. The projections and
the assumptions on which they are based are subject to significant
uncertainties, many of which are beyond the control of Eastern States or the
trust. ACTUAL 2000 DISTRIBUTABLE CASH, THEREFORE, COULD VARY SIGNIFICANTLY BASED
UPON CHANGES IN ANY OF THESE ASSUMPTIONS.

Distributable cash is particularly sensitive to natural gas prices. See
"-- Sensitivity of Projected Year 2000 Distributable Cash to Natural Gas Prices"
which shows estimated effects on projected year 2000 distributable cash from
changes in natural gas prices. As a result of the effects of the "collar"
arrangement described above during the year 2000, however, distributable cash
for production after the year 2000 will be more sensitive to changes in
prevailing gas prices than is reflected in the referenced disclosure.

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of each year, when historically lower gas prices are realized. For example, in
the year 2000, Eastern States expects to drill on the underlying properties
approximately 15 wells in the first quarter, approximately 55 wells in the
second quarter, approximately 80 wells in the third quarter and approximately 50
wells in the fourth quarter. ACCORDINGLY, THE PROJECTED YEAR 2000 DISTRIBUTABLE
CASH IS NOT NECESSARILY INDICATIVE OF DISTRIBUTIONS FOR FUTURE YEARS. A PORTION
OF EACH DISTRIBUTION MAY REPRESENT A RETURN OF YOUR ORIGINAL INVESTMENT, RATHER
THAN A RETURN ON YOUR ORIGINAL INVESTMENT. FOR A DESCRIPTION OF THE RISKS
ASSOCIATED WITH THE DEPLETING NATURE OF THE ASSETS OF THE TRUST, SEE "RISK
FACTORS -- NET PROCEEDS ARE DERIVED FROM THE SALE OF DEPLETING ASSETS."

PRODUCTION FROM
PRODUCTION FROM NEW WELLS ON COMBINED NET
UNDERLYING WELLS UNDERLYING LEASES PROFITS INTEREST
---------------- ----------------- ----------------
($ IN THOUSANDS)

Underlying Properties
Volumes Produced:
Natural gas:
Gross production (MMcf)..................... 16,485 5,248 13,713
Less a 1% allowance for
facilities maintenance (MMcf)............ (165) (53) (137)
------- -------- -------
Net production (MMcf)....................... 16,320 5,195 13,576
Oil:
Gross production (MBbls).................... 15.0 -- 12.0
Less a 1% allowance for
facilities maintenance (MBbls)........... (0.2) -- (0.1)
------- -------- -------
Net production (MBbls)...................... 14.8 -- 11.9
Assumed Sales Price of Natural Gas:
NYMEX (MMbtu)................................. $ 2.50
Plus Appalachian Basin and Contract Premium
(MMbtu)..................................... 0.28
-------
Average Sales Meter Price (MMbtu)........... 2.78
Plus Btu Adjustment........................... 0.36
-------
Average Sales Meter Price (Mcf)............. 3.14
Less Third Party Gathering and Compression
Charge (Mcf)................................ (0.16)
-------
Average Net Sales Meter Price (Mcf)........... 2.98
Less Compressor Fuel and Line Loss............ (0.16)
Less Eastern States' Gathering and
Compression Charge (Mcf).................... (0.23)
-------
Average Net Wellhead Price (per Mcf)........ $ 2.59 $ 2.59 $ 2.59
======= ======== =======
Assumed Sales Price of Oil (per Bbl)............. $ 18.00 -- $ 18.00
======= ======== =======
Calculation of Distributable Cash
Revenues:
Natural gas sales............................. $42,236 $ 13,446 $35,134
Oil sales..................................... 267 -- 213
------- -------- -------
Total.................................... 42,503 13,446 35,347
------- -------- -------

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PRODUCTION FROM
PRODUCTION FROM NEW WELLS ON COMBINED NET
UNDERLYING WELLS UNDERLYING LEASES PROFITS INTEREST
---------------- ----------------- ----------------
($ IN THOUSANDS)

Costs:
Production and property taxes................. 3,443 1,089 2,863
Production costs.............................. 4,510 302 3,639
Development costs and drilling overhead....... -- 44,249 4,425
Overhead...................................... 1,875 115 1,511
------- -------- -------
Total.................................... 9,828 45,755 12,438
------- -------- -------
Net proceeds.................................. 32,675 (32,309) 22,909
Net profits percentage........................ 80% 10%
------- -------- -------
Trust cash.................................... 26,140 (3,231) 22,909
Trust administrative expenses................. 300
-------
Trust distributable cash...................... $22,609
=======
Trust distributable cash per trust unit
(10,500,000 trust units).................... $ 2.15
=======

CASH DISTRIBUTION AS A PERCENTAGE
AMOUNT OF $20.00 TRUST UNIT PRICE
------ ---------------------------------

Per Trust Unit (10,500,000 trust units):
Total cash distributions (and taxable income before
depletion)........................................... $ 2.15 10.75%
Cost depletion tax deduction............................ (0.91)
------
Taxable income.......................................... 1.24
Income tax rate(a)...................................... 39.6%
------
Income tax to unitholders............................... (0.49)
------
Net cash distributions after tax to unitholders......... $ 1.66 8.30%
====== =====

- ---------------

(a) Assumes maximum federal effective tax rate applicable to individuals, but
does not take into account state income taxes that may be payable by
unitholders to Kentucky and West Virginia or their state of residence.

SIGNIFICANT ASSUMPTIONS USED TO PREPARE THE PROJECTED YEAR 2000 DISTRIBUTABLE
CASH

Timing of Actual Distributions. In preparing the projected year 2000
distributable cash described above and the sensitivity tables below, the
projected revenues and expenses of the trust were calculated based on the terms
of the transfer documents creating the net profits interests. These calculations
are described under "Computation of Net Proceeds," except that amounts for the
projection and sensitivity tables were calculated on an accrual or production
basis rather than the cash basis prescribed by the transfer documents. As a
result, the proceeds of production for the fourth quarter of the year 2000, and
reflected in the projection and tables, will actually enter into the calculation
of net proceeds to be received by the trust and distributed to unitholders on or
before March 25, 2001, since payments are made to Eastern States for sales of
production 55 to 60 days after the month of sale. Net proceeds from production
for the fourth quarter of 1999 will in fact be received by the trust and
distributed to unitholders in March 2000. The actual amount of the distribution
received by trust unitholders in the first quarter of the year 2000 will be
based on actual production during the quarter commencing October 1, 1999.
Accordingly, the projections represent an estimate of cash that would be
distributed to unitholders on or before June 25, 2000, September 25, 2000,
December 25, 2000 and March 25, 2001 and relate to production for the year 2000.

Production Estimates. Production estimates for the year 2000 are based on
estimates for the underlying properties by Ryder Scott as described in their
reserve report included as Exhibit A to this prospectus. Production from the
underlying properties for the year 2000 is estimated to be 21.8 Bcfe, net to
Eastern States. Eastern States then adjusts such production estimates by
deducting 1% as an allowance

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33

for facilities maintenance. For example, from time to time gathering or
transmission pipelines, production equipment or other facilities are shut down
for scheduled or unscheduled maintenance, which can reduce volumes produced from
Eastern States' wells below expected levels. Differing levels of production will
result in different levels of distributions and cash returns.

Natural Gas Prices. Natural gas prices assumed in the year 2000 projected
distributable cash estimate are based on wellhead prices for natural gas. The
wellhead price of $2.59 per Mcf was determined as follows:

NYMEX Price. Eastern States assumed a NYMEX price of $2.50 per MMbtu
in calculating the average wellhead natural gas price, which is the
mid-point of the "collar" arrangement described above. The NYMEX futures
market for the year 2000 as of September 30, 1999 was $2.66 per MMbtu.

Appalachian Basin and Contract Premium. Eastern States increased the
NYMEX price of $2.50 per MMbtu by an assumed Appalachian Basin premium of
$0.28 per MMbtu. For the period 1996 through 1998, natural gas price
indices in the Appalachian Basin have averaged an annual premium of $0.26
per MMbtu more than prices for natural gas contracts traded on the NYMEX
for the delivery of gas at Henry Hub, Louisiana. During these three years,
the average annual Appalachian Basin premium has ranged from $0.14 per
MMbtu to $0.47 per MMbtu. Historically, the premium has been higher in the
first and fourth quarters of the calendar year than in the second and third
quarters. In addition to the assumed Appalachian Basin premium of $0.26 per
MMbtu, Eastern States assumed an additional $0.02 per MMbtu premium
received pursuant to existing contracts that provide for the sale of
approximately 90% of Eastern States' natural gas production. The inclusion
of the Appalachian Basin premium results in an average sales meter price of
$2.78 per MMbtu. The price for natural gas sold under the existing gas
purchase contracts is based on a price published by Inside-FERC. This
published price is on a MMBtu basis. The projected year 2000 distributable
cash is presented on a Mcf basis. In order to adjust natural gas prices
from a MMBtu basis to a Mcf basis, it is necessary to increase the Mcf
price by the Appalachian Basin premium and the Btu adjustment. As discussed
below, the conversion to a Mcf basis is completed after the Btu adjustment.
For a description of the existing gas purchase contracts, including the
determination of the purchase price, see "The Underlying Properties -- Gas
Purchase Contracts."

Btu Adjustment. The average sales meter price of $2.78 per MMbtu is
increased by an assumed Btu adjustment of $0.36. This increase results in
an average sales meter price of $3.14 per Mcf. Eastern States assumes that
production from the underlying properties will have a Btu content for each
cubic foot of natural gas of 1,131 based on actual production data from the
underlying properties for the eight months ended August 31, 1999. This high
Btu content has historically provided an average 13.1% premium over the
standard measure of 1,000 Btu per cubic foot when calculating realized
prices on a per Mcf basis. The Btu adjustment converts the price per MMbtu
into a per Mcf equivalent by increasing the sum of the NYMEX price plus the
Appalachian Basin Premium by 13.1%.

Third Party Gathering and Compression Charge. Eastern States subtracts
an assumed average of $0.16 per Mcf for third party gathering and
compression charges from the average sales meter price to arrive at an
average net sales meter price of $2.98 per Mcf. Eastern States assumed
$0.16 per Mcf based on its estimate of the costs to transport natural gas
production from the underlying properties in the year 2000 through third
party gathering systems. As a result of the completion of various pipeline
projects by Eastern States in 1998 and early 1999, approximately one-third
of Eastern States' natural gas production is subject to third party
gathering and compression charges. Third party gathering and compression
charges are typically approximately $0.50 per Mcf. The assumed $0.16 per
Mcf charge represents a weighted average of all of Eastern States natural
gas production, assuming third parties continue to gather and compress
approximately one-third of Eastern States projected year 2000 natural gas
production.

29
34

Compressor Fuel and Line Loss. In accordance with the transfer
documents and in connection with gathering and compression services to be
performed by Eastern States, Eastern States will deduct a charge for
volumes consumed for compressor fuel and for volumes lost during gathering
and compression. These lost volumes are referred to as line loss. For
purposes of this presentation, an assumed fuel and line loss of
approximately 5.4% of the average net sales meter price of $2.98 per Mcf
has been deducted. This assumed fuel and line loss charge equates to $0.16
per Mcf. The amount deducted, that is, approximately 5.4% of the average
net sales meter price, is based on Eastern States' historical production
data. The actual amounts to be deducted will be based upon the actual
volumes so consumed or lost by Eastern States in performing these services,
which will vary based upon the actual volumes gathered and compressed by
Eastern States.

Eastern States' Gathering and Compression Charge. In accordance with
the transfer documents, Eastern States will deduct an assumed $0.23 per Mcf
for its gathering and compression charge. This charge represents estimated
gathering and compression costs of $0.09 per Mcf, plus reimbursement for
depreciation and a return on investment of its gathering and compression
systems of $0.14 per Mcf. The $0.09 per Mcf is equal to the actual cost per
Mcf incurred by Eastern States during the eight months ended August 31,
1999 to gather and compress natural gas produced from the underlying
properties. The $0.14 per Mcf is equal to the charge per Mcf that would
have been deducted by Eastern States during the eight months ended August
31, 1999 to reimburse it for depreciation and to provide a return on its
investment in its gathering and compression systems. The projected charge
of $0.23 per Mcf for natural gas gathered and compressed by Eastern States
has been projected in accordance with the projected year 2000 volumes
assumed to be gathered and compressed by Eastern States. For a further
description of these charges, see "Computation of Net Proceeds -- Net
Profits Interests."

In early 1999, Eastern States completed a major pipeline project which
reduced the amount of its natural gas production subject to third party
gathering and compression charges which increased net proceeds. These reduced
third party gathering and compression charges and corresponding increase in net
proceeds will be offset in part by the reimbursement to Eastern States for
depreciation and a return on investment of its gathering and compression systems
described above. However, if location, quality and other differentials return in
the future to more normal levels, there may be more significant differences
between the natural gas price received and the NYMEX price.

The adjustments to wellhead natural gas prices applied in the foregoing
tables are based upon an analysis by Eastern States of the historic price
differentials for production from the underlying properties with consideration
given to the Appalachian Basin premium, Btu content, both third party and
internal gathering and compression charges, and fuel and line loss that may
affect these differentials in the year 2000. There is no assurance that these
assumed differentials will recur in the year 2000 since they are dependent upon
numerous factors outside Eastern States' control. When natural gas prices
decline, the operators of the underlying properties may elect to reduce or
completely suspend production. No adjustments have been made to estimated year
2000 production to reflect potential reductions or suspensions of production.

Oil Prices. Oil sales are realized based on posted prices for Appalachian
Basin production, which has historically been priced at a discount of $2.00 to
$3.00 from the posted price for West Texas Intermediate crude oil.

Production Costs. For calendar year 2000, Eastern States will charge a
fixed overhead fee per well for production costs for wells on the underlying
properties. Except for those wells completed below 7,000 feet, Eastern States
will deduct a monthly fixed production fee of $170 per well for wells producing
five or more Mcf per day and $70 per well for those wells producing less than
five Mcf per day. For wells completed in a zone more than 7,000 feet below the
surface, Eastern States will charge $300 per month. Wells that are shut-in,
temporarily abandoned or otherwise inactive for mechanical reasons or pipeline
constraints or because they may no longer be economic to continue to produce
will be charged the applicable monthly fixed production cost if they are
completed in a zone above 7,000 feet and $300 if they are completed in a

30
35

zone below 7,000 feet. Each of these fixed costs is subject to adjustment
beginning April 1, 2001 in accordance with an industry standard set forth in the
accounting procedures in the transfer documents. The estimated costs for year
2000 are based upon the Ryder Scott reserve report included as Exhibit A to this
prospectus. The fixed amount of production costs deducted when calculating net
proceeds is reduced by approximately 3%, which amount represents the average
percentage working interest in the underlying properties that Eastern States
does not own. It is assumed that the other working interest owners will bear the
remaining portion of production costs. For a description of production costs,
see "Computation of Net Proceeds -- Net Profits Interests."

Development Costs and Drilling Overhead. In calculating net proceeds,
Eastern States will be reimbursed for all development costs attributable to the
underlying properties, plus a drilling overhead fee of $36,000 for each well
drilled or deepened to another formation, zone or horizon on the underlying
properties on or after September 1, 1999. This drilling overhead fee is subject
to adjustment beginning April 1, 2001 in accordance with an industry standard
set forth in the accounting procedures in the transfer documents. For the year
2000, Eastern States expects to drill approximately 200 wells on the underlying
leases resulting in development costs of approximately $44 million, which
includes a drilling overhead fee of $7.1 million. The drilling overhead fee,
which represents approximately 20% of estimated development cost, covers the
cost of geologists and engineers, as well as reimbursement for lease acquisition
costs, which in some cases are substantial. To take advantage of more favorable
weather conditions, Eastern States expects to seasonally adjust its drilling
activity and to drill more wells during the warmer months of each year, which
may result in higher than average annual capital expenditures during those
periods and lower than average annual capital expenditures during the winter
months. For a further description of these overhead charges, see "Computation of
Net Proceeds -- Net Profits Interests." It is assumed that Eastern States will
own a 98% working interest in all wells drilled on or after September 1, 1999.

Overhead. For the year 2000, Eastern States will charge a $65 per month
fixed overhead fee per producing well on the underlying properties. This fee
will continue to be charged in the event a well is shut-in, temporarily
abandoned or otherwise inactive. This overhead fee will no longer be charged
once a well is plugged and abandoned. Prior to the closing of this offering,
Eastern States has not charged an overhead fee. This fixed cost is subject to an
adjustment beginning April 1, 2001 in accordance with an industry standard set
forth in the accounting procedures in the transfer documents. This overhead fee
is in addition to the production fee described under "-- Production Costs"
above. The fixed amount of overhead deducted when calculating net proceeds is
reduced by approximately 3%, which amount represents the average percentage
working interest in the underlying properties that Eastern States does not own.
It is assumed that the other working interest owners will bear the remaining
portions of overhead.

Administrative Expenses. Trust administrative expenses for the year 2000
are assumed to be $300,000 ($0.03 per trust unit). For a further description of
the trust's administrative expenses, see "The Trust."

Projected After-Tax Cash Distributions as a Percentage of Trust Unit Price
of $20.00. Because the net profits interests are a depleting asset, a portion of
this distribution may be considered a return of your original investment. Except
for tax purposes, the portion that would be considered a return of original
investment is not determinable until the trust unit is sold by a trust
unitholder. For a discussion of alternative ways of measuring the depletion of
oil and natural gas assets, see "Risk Factors -- Net proceeds are derived from
the sale of depleting assets."

The Projected After-Tax Cash Distributions as a Percentage of Trust Unit
Price of $20.00 were computed by:

- taking into account a cost depletion tax deduction of $0.91 per trust
unit;

- determining the amount of federal income tax that would be paid on the
taxable income attributable to a unit at the highest effective tax rate
applicable to individuals for 1999 of 39.6%;
- subtracting the federal income tax to unitholders from the annual cash
distributions; and

- dividing the result by $20.00 per trust unit.

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36

Cost depletion is calculated by multiplying the assumed trust unit purchase
price of $20.00 by the cost depletion rate of 4.55%. Cost depletion is
recaptured upon sale of the trust units, which results in the taxation of any
gain on sale as ordinary income, as opposed to capital gain, up to the amount of
cost depletion previously deducted.

When the distributions are less than $0.91 per trust unit, the Projected
After-Tax Cash Distributions as a Percentage of Trust Unit Price of $20.00 would
be the same or greater than the Projected Pre-Tax Cash Distributions as a
Percentage of Trust Unit Price because of cost depletion. In all instances, each
trust unitholder is assumed to have a regular federal income tax liability
sufficient to utilize the depletion deduction. Alternative minimum tax and state
income tax implications have not been considered.

SENSITIVITY OF PROJECTED YEAR 2000 DISTRIBUTABLE CASH TO NATURAL GAS PRICES

Eastern States prepared the following unaudited tables, which demonstrate
the estimated effect that changes in the estimated year 2000 production and in
the price for natural gas could have on the trust's distributable cash. Average
annual NYMEX natural gas prices of less than $ per MMbtu or more than
$ per MMbtu are not included in the tables below because prices for the
trust's portion of year 2000 production is subject to the hedge agreement
provided by Eastern States. For a description of this hedge agreement, see
"-- Projected Year 2000 Distributable Cash" that begins on page 26.

The following tables show:

- the projected distributable cash per trust unit for the year 2000 on the
accrual or production basis;

- the resulting projected distributable cash per trust unit as a percentage
of the purchase price of the trust unit; and
- the resulting projected distributable cash per trust unit as a percentage
of the purchase price of the trust unit, after payment of all federal
income tax, net of available deductions at the highest effective federal
tax rate applicable to individuals of 39.6%.

THE TABLES BELOW ARE NOT A PROJECTION OR FORECAST OF THE ACTUAL OR
ESTIMATED RESULTS FROM AN INVESTMENT IN THE TRUST UNITS. THE PURPOSE OF THE
TABLES IS TO ILLUSTRATE THE SENSITIVITY OF DISTRIBUTABLE CASH AND DISTRIBUTABLE
CASH AS A PERCENTAGE OF TRUST UNIT PURCHASE PRICE TO CHANGES IN THE PRICES OF
NATURAL GAS. THERE IS NO ASSURANCE THAT THE ASSUMPTIONS DESCRIBED ABOVE WILL
ACTUALLY OCCUR OR THAT THE PRICES OF NATURAL GAS WILL NOT CHANGE BY AMOUNTS
DIFFERENT FROM THOSE SHOWN IN THE TABLES.

Due to the seasonal demand for natural gas, the amount of quarterly cash
distributions from the trust is expected to vary during the year. Quarterly
distributions will also vary based on the timing of development expenditures and
the net proceeds, if any, generated by development projects.

SENSITIVITY OF PROJECTED TOTAL YEAR 2000 CASH DISTRIBUTIONS PER TRUST UNIT

% OF YEAR 2000 RESERVE REPORT ESTIMATED PRODUCTION AVERAGE ANNUAL NYMEX NATURAL GAS PRICE PER MMBTU
- -------------------------------------------------- -----------------------------------------------------
$1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $3.25
----- ----- ----- ----- ----- ----- -----

90%.......................................... $1.04 $1.31 $1.58 $1.84 $2.11 $2.38 $2.65
95%.......................................... 1.15 1.43 1.72 2.00 2.28 2.56 2.85
100%......................................... 1.26 1.56 1.86 2.15 2.45 2.75 3.04
105%......................................... 1.37 1.68 2.00 2.31 2.62 2.93 3.24
110%......................................... 1.48 1.81 2.14 2.46 2.79 3.12 3.44

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37

SENSITIVITY OF PROJECTED YEAR 2000 PRE-TAX CASH DISTRIBUTIONS AS A

PERCENTAGE OF TRUST UNIT PRICE OF $20.00

90%.......................................... 5.21% 6.55% 7.88% 9.22% 10.56% 11.89% 13.23%
95%.......................................... 5.76 7.17 8.58 9.99 11.40 12.81 14.23
100%......................................... 6.31 7.80 9.28 10.75 12.25 13.74 15.22
105%......................................... 6.86 8.42 9.98 11.54 13.10 14.66 16.22
110%......................................... 7.41 9.05 10.68 12.31 13.95 15.58 17.21

SENSITIVITY OF PROJECTED YEAR 2000 AFTER-TAX CASH DISTRIBUTIONS AS A

PERCENTAGE OF TRUST UNIT PRICE OF $20.00

90%.......................................... 4.94% 5.75% 6.56% 7.36% 8.17% 8.98% 9.79%
95%.......................................... 5.28 6.13 6.98 7.83 8.68 9.54 10.39
100%......................................... 5.61 6.51 7.40 8.30 9.20 10.09 10.99
105%......................................... 5.94 6.88 7.82 8.77 9.71 10.65 11.59
110%......................................... 6.27 7.26 8.25 9.23 10.22 11.21 12.19

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38

THE UNDERLYING PROPERTIES

GENERAL

The underlying properties are located in the Appalachian Basin states of
Kentucky and West Virginia. The underlying properties consist of Eastern States'
interests in 2,471 existing producing natural gas wells and interests in wells
that Eastern States will drill on or after September 1, 1999 on all of Eastern
States' oil and gas leasehold interests in the states of Kentucky and West
Virginia, except for the excluded interests discussed below. The trust will not
have a net profits interest in any properties or interests acquired by Eastern
States on or after September 1, 1999. The working interests of Eastern States
comprising the underlying properties are held under leases and farmout
agreements with third parties. Substantially all of the working interests are
subject to landowners' royalties and may be subject to additional royalties or
other obligations burdening the working interests. These royalties do not bear
lease operating expenses, but reduce the revenue interests attributable to the
underlying properties.

Eastern States has, on average, greater than a 97% working interest and a
net revenue interest of approximately 87% in the underlying properties. Eastern
States currently operates all of the wells on the underlying properties. Ryder
Scott estimates that 331 Bcfe of proved developed and 437 Bcfe of proved
undeveloped natural gas reserves are attributable to the underlying properties,
which estimates are the subject of their reserve report as of August 31, 1999
included as Exhibit A to this prospectus. Ryder Scott estimates that 211 Bcfe of
proved developed reserves and 29 Bcfe of proved undeveloped reserves are
attributable to the net profits interest free of future costs and expenses,
which estimates are the subject of their reserve report included as Exhibit B to
this prospectus.

Eastern States currently owns approximately 4,700 producing wells in
Kentucky and West Virginia. When selecting producing wells to be included in the
2,471 underlying wells, Eastern States excluded wells with any of the following
characteristics:

- approximately 1,350 wells owned by a financial institution that are
Section 29 production payment properties, most of which are operated by
Eastern States;

- approximately 220 wells drilled during the 20 months ended August 31,
1999, each of which has a limited production history and a high decline
profile;

- approximately 10 wells with high operating costs;

- approximately 300 marginal producing wells and associated leases, i.e.,
producing less than 2 Mcf per day, which will most likely have to be
abandoned in the next five to 10 years;

- approximately 50 wells with title or consent issues; and

- approximately 300 wells in which Eastern States is not the operator.

Eastern States' transfer to the trust of a net profits interest in 2,471
underlying wells in Kentucky and West Virginia is intended to create a diversity
of well profiles and a diversity of value. The well with the highest discounted
net present value represents less than 0.5% of the value of all underlying
wells. The inclusion of a large number of future drilling opportunities on the
underlying leases along with the underlying wells will provide statistical and
geological diversity in more than one potential producing zone in Kentucky and
West Virginia. Approximately 73% of the 2,471 underlying wells are located in
West Virginia and approximately 27% are located in Kentucky. All of the
underlying wells, except for one, are producing and profitable. One well is
temporarily shut-in and is expected to resume production in November and be
profitable at that time.

Eastern States excluded leases and other interests in Kentucky and West
Virginia from the underlying leases with any of the following characteristics:

- leases and mineral interests in Kentucky pertaining to the Rome
exploration area, which is characterized by high exploration risk;

- the portion of underlying leases that have been farmed out to third
parties; and

- leases or interests with known transfer or title issues, including all
potential coalbed methane exploration and developmental rights.

34
39

Eastern States has an inventory of approximately 1.2 million gross acres,
excluding the Rome exploration area but before giving effect to the other
excluded interests, comprising the underlying leases and has established a
drilling schedule for new sites in Kentucky and West Virginia. Eastern States
anticipates drilling an average of 200 wells per year on the underlying leases
for at least the next five years. Without future development, the underlying
properties would typically experience an average 5.5% annual decline in
production. Planned development expenditures included in the Ryder Scott reserve
report, which, total $285 million through 2007 or $28.5 million net to the
trust, are expected to reduce the natural rate of decline in production to an
average of 3% per year. While the number of wells to be drilled on an annual
basis following the offering is subject to a number of factors beyond the
control of Eastern States, the underlying leases are expected to yield a number
of drillsites which would sustain development of the properties at current
levels for the foreseeable future.

If Eastern States, on or after September 1, 1999, successfully drills,
deepens or recompletes any of the 2,471 underlying wells or any well within
1,000 feet of any of the 2,471 underlying wells at or above the base of the
Devonian Shale, the trust will have an 80% net profits interests in the net
proceeds from the sale of natural gas from these wells. The base of the Devonian
Shale ranges in Kentucky and West Virginia from 2,500 feet to 7,500 feet below
the surface. If Eastern States, on or after September 1, 1999, commences a well
on the underlying leases, except for wells located within 1,000 feet of an
existing well and completed above the base of the Devonian Shale, or drills,
deepens or recompletes any of the 2,471 underlying wells on the underlying
leases below the base of the Devonian Shale, the trust will have a 10% net
profits interest in the net proceeds from the sale of natural gas from these
wells. Currently, Eastern States has no proved reserves below the base of the
Devonian Shale within the underlying leases.

Although Eastern States has not obtained title opinions with respect to the
drillsites, Eastern States is not aware of any title deficiencies that would
preclude it from drilling any of the locations. Eastern States has drilled over
400 wells in Kentucky and West Virginia since 1994 with a completion rate of
approximately 98%, and expects the completion rate on wells drilled on or after
September 1, 1999 to be similar. Moreover, the drillsites are expected to have
the same general production characteristics as the producing wells included in
the underlying properties. No assurance can be given, however, that any wells
drilled on or after September 1, 1999 will be successful or produce in
commercial quantities. For a further discussion of Eastern States' title to the
drillsites referred to above, see "-- Title to Properties."

Production from the wells to which the underlying properties relate is
typically subject to, in one degree or another:

- landowner royalties and other burdens and obligations retained under oil
and gas leases;
- relocation provisions under oil and gas leases with coal mining entities;
- overriding royalty interests; and
- other working interests in the wells.

Royalty and overriding royalty interests entitle the holders thereof to a
percentage of the oil and natural 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 natural gas to render it marketable; and
- transportation or gathering and compression 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. Certain leases are
not burdened by any royalty interests and only a minor portion of the underlying
leases are burdened by overriding royalties.

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40

THE APPALACHIAN BASIN

The Appalachian Basin is the oldest and geographically one of the largest
oil and natural gas producing regions in the United States. From 1859 to 1993,
more than 700,000 wells have been drilled in the Appalachian Basin and have
produced an estimated three billion barrels of oil and 42 trillion cubic feet of
natural gas. Although the Appalachian Basin has known sedimentary formations
indicating the potential for oil and natural gas reservoirs to depths of 13,000
feet or more, oil and natural gas is currently produced principally from shallow
blanket formations at depths of 1,000 to 7,000 feet. These formations are
characterized by slow recovery of the reserves in place, low rates of production
and wells that generally produce for longer than 20 years and often more than 50
years. Although commercial success varies widely from well to well, operators in
the Appalachian Basin historically have experienced drilling completion rates
exceeding 90% in these shallow formations.

For the period 1991 through 1998, wellhead natural gas prices in the
Appalachian Basin have averaged on an annual basis $0.25 per MMbtu more than
prices for natural gas contracts traded on the NYMEX for the delivery of natural
gas at Henry Hub, Louisiana. During these eight years, the Appalachian Basin
annual premium has ranged from $0.14 per MMbtu to $0.47 per MMbtu. This premium
has averaged $0.26 MMbtu for the last three years. The higher average prices are
principally due to the proximity to a substantial number of industrial and
commercial end users in the northeast United States. The Appalachian Basin
premium is offset, at least in part, by the high gathering and compression costs
in the Appalachian Basin.

The combination of its long-lived production, low drilling costs, high
drilling completion rates at shallow depths and proximity to natural gas markets
has had a substantial impact on the development of the Appalachian Basin
resulting in a highly fragmented operating environment. In 1998, Kentucky and
West Virginia had more than 500 independent operators and more than 85,000
producing oil and natural gas wells. Also, the historical availability of tax
shelter capital has resulted in extensive drilling in the shallow formations
with these low technical risk characteristics.

DISTRICTS COMPRISING THE UNDERLYING PROPERTIES

The districts comprising the underlying properties are as follows:

Pikeville Area, Kentucky

The Pikeville Area includes approximately 34% of the total net proved
reserves in the underlying properties. The underlying properties in this
district are concentrated in Pike, Knott, Martin, Floyd and Breathitt counties,
Kentucky on approximately 262,000 gross acres, which excludes the Rome
exploration area. Natural gas is produced predominantly from the Maxton, Big
Lime, Berea and Devonian Shale formations at depths ranging from 1,000 to 5,500
feet. Sales meter production attributable to the underlying properties averaged
13 MMcfe per day during the first eight months of 1999. Significant development
potential still remains in this district, with 505 proved undeveloped locations
identified for exploitation as of August 31, 1999.

Brenton Area, West Virginia

The Brenton Area includes approximately 38% of the total net proved
reserves in the underlying properties. The underlying properties in this
district are located mainly in Logan, Mingo, McDowell and Wyoming counties in
southern West Virginia on approximately 397,000 gross acres. Natural gas is
produced predominantly from the Maxton, Big Lime, Berea and Devonian Shale
formations at depths ranging from 2,000 to 7,000 feet. Sales meter production
attributable to the underlying properties averaged 14 MMcfe per day for the
first eight months of 1999. Significant development potential still remains in
this district, with 674 proved undeveloped locations identified for exploitation
as of August 31, 1999.

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41

Madison Area, Eastern West Virginia

The Madison Area includes approximately 20% of total net proved reserves in
the underlying properties. The underlying properties in this district are
located in Lincoln, Kanawha, Boone, Raleigh, Fayette, Nicholas and Clay counties
in south central West Virginia on approximately 374,000 gross acres. Natural gas
is produced predominantly from the Maxton, Big Lime, Big Injun, Weir, Berea and
Devonian Shale formations at depths ranging from 1,700 to 6,000 feet. Sales
meter production attributable to the underlying properties averaged 11 MMcfe per
day for the first eight months of 1999. Significant development potential still
remains in this district, with 296 proved undeveloped locations identified for
exploitation as of August 31, 1999.

Weston Area, West Virginia

The Weston Area includes approximately 8% of the total net proved reserves
in the underlying properties. The underlying properties in this district are
located largely in Jackson, Gilmer, Doddridge, Roane, Calhoun, Harrison and
Wetzel counties in northern West Virginia on approximately 192,000 gross acres.
Natural gas is produced from Upper Devonian sandstone formations at depths
ranging from 1,800 to 5,000 feet. Sales meter production attributable to the
underlying properties averaged 8 MMcfe per day for the first eight months of
1999. Some development potential remains in this district, with 53 proved
undeveloped locations identified for exploitation as of August 31, 1999.

HISTORICAL RESULTS FROM THE UNDERLYING PROPERTIES

The following table provides oil and natural gas wellhead volumes, average
realized sales prices, revenues and direct operating expenses relating to the
underlying properties for 1996, 1997 and 1998 and for the eight-month periods
ended August 31, 1998 and 1999. The related pro forma adjustments for the year
ended December 31, 1998 and the eight months ended August 31, 1999 are also
shown. Eastern States did not own all of the underlying properties for each of
the periods indicated. The audited statements of revenues and direct operating
expenses of the underlying properties for the years ended December 31, 1996,
1997 and 1998 and unaudited statements for the eight-month periods ending August
31, 1998 and 1999 begin on page F-3 in this prospectus. The pro forma
adjustments reflect changes to historical results as if the offering had
occurred on December 31, 1997 and give effect to the adjustments described on
page F-13 in this prospectus.

EIGHT MONTHS
YEAR ENDED DECEMBER 31, ENDED AUGUST 31,
--------------------------- -----------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER UNIT DATA)

Wellhead volumes:
Natural gas (MMcf)........................... 19,318 19,960 19,040 13,184 11,967
Oil (MBbls).................................. 35.1 30.6 20.4 12.9 18.9
Average realized sales prices:
Natural gas (per Mcf)........................ $ 2.84 $ 2.62 $ 2.20 $ 2.27 $ 2.14
Oil (per Bbl)................................ $ 19.29 $ 17.35 $ 11.86 $ 12.17 $ 12.17
Revenues:
Natural gas sales............................ $54,877 $52,303 $41,835 $29,879 $25,594
Oil sales.................................... 677 531 242 157 230
------- ------- ------- ------- -------
Total................................ 55,554 52,834 42,077 30,036 25,824
------- ------- ------- ------- -------
Direct operating expenses:
Production and property taxes................ 5,179 4,872 3,809 2,713 2,338
Production expenses.......................... 6,300 5,106 3,603 2,401 2,401
------- ------- ------- ------- -------
Total................................ 11,479 9,978 7,412 5,114 4,739
------- ------- ------- ------- -------
Excess of revenues over direct operating
expenses.................................. $44,075 $42,856 $34,665 $24,922 $21,085
======= ======= ======= ======= =======

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42

EIGHT MONTHS
YEAR ENDED ENDED AUGUST 31,
DECEMBER 31, 1998 1999
----------------- -------------------
(IN THOUSANDS, EXCEPT PER UNIT DATA)

Excess of revenues over direct operating costs.............. $34,665 $21,085
Pro Forma Adjustments:
Revenue................................................... (2,439) (1,533)
Production expenses....................................... (897) (599)
Overhead.................................................. (1,870) (1,250)
------- -------
Total pro forma adjustments....................... (5,206) (3,382)
Net proceeds.............................................. 29,459 17,703
Net profits percentage.................................... 80% 80%
------- -------
Trust cash................................................ 23,567 14,162
Trust administrative expenses............................. (300) (200)
------- -------
Trust distributable cash.................................. $23,267 $13,962
======= =======
Trust distributable cash per unit (10,500,000 units issued
and outstanding)....................................... $ 2.22 $ 1.33
======= =======

DISCUSSION AND ANALYSIS OF HISTORICAL RESULTS FROM THE UNDERLYING PROPERTIES

The excess of revenues over direct operating expenses from the underlying
properties was $44,075,000 for 1996, $42,856,000 for 1997 and $34,665,000 for
1998. The excess of revenues over direct operating expenses was $24,922,000 for
the eight months ended August 31, 1998 and $21,085,000 for the eight months
ended August 31, 1999. The changes in excess of revenues over direct operating
expenses were primarily related to changes in volumes and prices. Natural gas
sales accounted for greater than 99% of total revenues for the three-year period
ended December 31, 1998 and the eight-month period ended August 31, 1999.

Natural Gas Volumes. Natural gas sales volumes from the underlying
properties increased 3.3% from 1996 to 1997, decreased 4.6% from 1997 to 1998
and decreased 9.2% from the eight-month period ending August 31, 1998 to the
eight-month period ending August 31, 1999. The increase was primarily
attributable to development projects in 1996 and 1997 and the decrease in 1998
was primarily attributable to the fact that none of the development wells
drilled in 1998 and 1999 are included in the underlying properties. Also, the
wells drilled in 1997 experienced a higher production decline in the eight
months ended August 31, 1998 as compared to the eight months ended August 31,
1999.

Natural Gas Prices. The average realized natural gas sales price decreased
7.7% from $2.84 per Mcf in 1996 to $2.62 per Mcf in 1997, decreased 16% from
$2.62 per Mcf in 1997 to $2.20 per Mcf in 1998 and decreased 5.7% from $2.27 per
Mcf in the eight-month period ending August 31, 1998 to $2.14 per Mcf in the
eight-month period ending August 31, 1999. Gas prices for the underlying
properties have generally tracked Appalachian Basin market prices. Gas prices
realized in 1996 for Appalachian Basin natural gas were high due to a prolonged
cold weather period in January and February 1996. The amount of natural gas in
storage in the northeastern United States was at extremely low levels and prices
remained strong throughout the year. As a result of this cold weather, the
Appalachian Basin premium averaged $0.47 per MMbtu for 1996. NYMEX gas prices
remained strong in 1996 and 1997, while the Appalachian Basin premium was weak
in 1997 due to unusually warm winter weather in the Northeast. As a result,
prices realized for 1997 were 7.7% lower. In 1998, both the NYMEX price and the
Appalachian Basin premium weakened due in part to the second consecutive warm
winter in the Northeast. This caused 1998 realized prices to drop 16% as
compared to 1997. Prices continued to drop in the first and second quarter of
1999. Natural gas prices in July 1999 and for the rest of the year have
strengthened for both NYMEX and the Appalachian Basin premium in anticipation of
a normal winter in the Northeastern United States. See the table below for
market prices.

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43

Set forth below is a table that reflects average NYMEX closing prices and
average Appalachian Basin prices for 1996, 1997, 1998 and the eight months ended
August 31, 1999, and the average annualized Appalachian Basin premiums for such
periods based upon such average annualized prices. The average Appalachian Basin
prices shown below represent the average natural gas prices published by Inside
FERC -- Appalachian Basin for CNG Transmission Corp. and Columbia Gas
Transmission Corp.

AVERAGE
AVERAGE AVERAGE ANNUALIZED AVERAGED
NYMEX APPALACHIAN APPALACHIAN ANNUALIZED
CLOSING BASIN BASIN APPALACHIAN
PRICES PRICES PREMIUM BASIN
($/MMBTU) ($/MMBTU) ($/MMBTU) PREMIUM
--------- ----------- ----------- -----------

1996..................................... $2.59 $3.06 $0.47 18.1%
1997..................................... 2.59 2.76 0.17 6.6
1998..................................... 2.11 2.25 0.14 6.6
Eight months ended August 31, 1999....... 2.07 2.22 0.15 7.2

Natural gas prices have continued to increase since the spring of 1999 and the
average Appalachian Basin natural gas price for September 1999 was $3.05 per
MMbtu, which consists of an Appalachian Basin premium of $0.14 per MMbtu.

The average realized sales price of natural gas production from the
underlying properties during 1998 was $2.20 per Mcfe, which is approximately
$0.09 above the average of the monthly closing NYMEX natural gas futures
contract prices in 1998. The average realized sales price of natural gas
production from the underlying properties during 1998 on a pro forma basis as if
the offering had closed on December 31, 1997 was $2.05 per Mcfe, which is
approximately $0.06 below the average of the monthly closing NYMEX natural gas
futures contract prices in 1998. This difference in the NYMEX futures prices is
due to the lower than average Appalachian Basin premium in 1998, which resulted
primarily from significantly warmer than normal average prevailing winter
temperatures in 1998, as well as high gathering and compression charges.

Direct operating expenses. Direct operating expenses decreased 13.1% from
$11,479,000 in 1996 to $9,978,000 in 1997, followed by a 25.7% decrease to
$7,412,000 in 1998. The production costs for 1996 and for the six months ended
June 30, 1997 show operating costs of the predecessor owner, Blazer Energy.
Since the acquisition, Eastern States has reduced these costs. For the
eight-month period ending August 31, 1998 compared to the eight-month period
ending August 31, 1999, direct operating expenses decreased 7.3% from $5,114,000
to $4,739,000 due to continued efficiencies as a result of the assimilation of
the Blazer properties.

Development costs. Virtually all of the underlying properties were either
purchased or drilled by Eastern States in the four-year period from 1994 to
1997. Development costs rose 86.7% from $12,024,000 in 1996 to $22,445,000 in
1997 as major development projects were completed. Eastern States expects
development costs on the underlying leases to be approximately $44 million per
year for at least the next five years. None of the wells drilled in 1998 and
1999 are included in the underlying properties because of their higher decline
profile compared to the current decline profile of wells drilled in the
four-year period from 1994 to 1997. Development costs incurred by Blazer Energy
prior to its acquisition by Eastern States on June 30, 1997 have not been
included in the historical results table above.

The following table shows the development costs relating to natural gas
wells drilled by Eastern States in Kentucky and West Virginia for 1996, 1997 and
1998 and for the eight months ended August 31, 1999. The table also shows
projected development costs for the four months ended December 31, 1999 and the
projected development costs included in projected year 2000 distributable cash.

The development costs for 1996 and 1997 include those for wells drilled by
Eastern States on the underlying properties, but do not include those for wells
drilled by Blazer Energy on the underlying properties for the period prior to
Eastern States' acquisition of Blazer Energy on June 30, 1997, which are not
available to Eastern States.

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44

The development costs for 1998 and the eight months ended August 31, 1999
are for wells drilled by Eastern States in Kentucky and West Virginia. Eastern
States has excluded those wells from the 2,471 underlying wells to be
transferred to the trust due to their limited production history and relatively
high decline profile.

The projected development costs for the four months ended December 31, 1999
and for the year ended December 31, 2000 are based on average costs to develop
undeveloped properties. Volumes for these time periods are derived from the
Ryder Scott reserve report for the underlying properties.

TOTAL FINDING AND
DEVELOPMENT DEVELOPMENT DEVELOPMENT
NATURAL COSTS COSTS NET COSTS
GAS WELLS EXCLUDING DRILLING INCLUDING RESERVE INCLUDING
----------- OVERHEAD OVERHEAD OVERHEAD ADDITIONS OVERHEAD
GROSS NET ($ IN MILLIONS) ($ IN MILLIONS)(A) ($ IN MILLIONS) (BCFE) ($/MCFE)
----- --- --------------- ------------------ --------------- --------- -----------

Year Ended December 31, 1996..... 54 53 $ 9.4 $2.6 $12.0 15.2 $0.79
Year Ended December 31, 1997..... 88 88 17.5 5.0 22.4 27.9 0.80
Year Ended December 31, 1998..... 165 162 36.2 5.8 42.0 53.4 0.79
Eight months ended August 31,
1999........................... 114 111 21.3 4.0 25.3 42.6 0.59
Four months ended December 31,
1999 (projected)............... 67 66 12.4 2.4 14.8 26.0 0.57
--- --- ----- ---- ----- ----
Total 1999....................... 181 177 33.7 6.4 40.1 68.6 0.58
--- --- ----- ---- ----- ----
Year ended December 31, 2000
(projected).................... 200 197 37.1 7.1 44.2 68.6 0.64

- ---------------

(a) Drilling overhead for 1996 and 1997 is based on Eastern States actual
overhead allocated to its drilling operations. For 1998, the eight month and
four month periods of 1999 and year 2000, the amounts are based on the
drilling overhead fee of $36,000 to be deducted in calculating net proceeds
payable to the trust for each well drilled on the underlying properties.

RESERVES

Ryder Scott estimated oil and natural gas reserves attributable to the
underlying properties and the net profits interests as of August 31, 1999, which
are the subject of their reserve reports included as Exhibit A and Exhibit B to
this prospectus. Numerous uncertainties are inherent in estimating reserve
volumes and values, and the estimates are subject to change as additional
information becomes available. The reserves actually recovered and the timing of
production of the reserves may vary significantly from the original estimates.

Ryder Scott calculated reserve quantities and revenues for the net profits
interests from projections of reserves and revenues attributable to the combined
interests of the trust and Eastern States in the underlying properties. Because
the trust owns net profits interests and not a specific ownership percentage of
the oil and natural gas reserve quantities, proved reserves for the trust's net
profits interests attributable to the 2,471 underlying wells are calculated by
subtracting from 80% of proved reserves, reserve quantities of a sufficient
value to pay 80% of the future estimated production and development costs,
before overhead and trust administrative expenses that are deducted in
calculating net proceeds. Proved reserves for the net profits interests
attributable to the proved undeveloped reserves owned by Eastern States in
Kentucky and West Virginia are calculated by subtracting from 10% of the proved
undeveloped reserves, reserve quantities of a sufficient value to pay 10% of the
future estimated production and development costs, before overhead and trust
administrative expenses that are deducted in calculating net proceeds.
Accordingly, proved reserves for the net profits interests reflect quantities
that are calculated after reductions for future production and development costs
and expenses based on the price and cost assumptions used in the reserve
estimates. The total proved reserves deducted for the future costs and expenses
in determining the net profits interests were approximately 67 Bcfe.

The standardized measure of discounted future net cash flows presented
below was prepared using assumptions required by the Financial Accounting
Standards Board. These assumptions include the use of

40
45

August 31, 1999 prices for natural gas and costs for estimated future
development and production expenditures to produce the proved reserves.

Because natural gas prices are influenced by seasonal demand, use of August
31, 1999 prices may not be the most accurate basis for estimating future
revenues or reserve data. Future net cash flows are discounted at an annual rate
of 10% as required by the Financial Accounting Standards Board. There is no
provision for federal income taxes because future net revenues are not subject
to taxation at the trust level. The weighted average August 31, 1999 wellhead
natural gas price used to determine the standardized measure was $2.75 per Mcf
for the underlying properties and $2.61 per Mcf for the net profits interests.
The $0.14 per Mcfe difference represents reimbursement for depreciation and a
return on Eastern States' investment in its gathering and compression systems.

During 1999, Eastern States filed estimates of operated oil and natural gas
reserves as of December 31, 1998 with the U.S. Department of Energy on Form
EIA-23. These estimates are consistent with the reserves reported in this
prospectus for the underlying properties as of December 31, 1998, with the
exception that Form EIA-23 includes only reserves from properties that had been
acquired and were operated by Eastern States at that date. Neither Eastern
States nor the trust has reported reserves for the net profits interests with
any Federal authority or agency prior to the filing of this prospectus.

Proved Reserves

The following table shows proved developed reserves, proved undeveloped
reserves, total proved reserves, future net revenues and the standardized
measure discounted future net cash flows at August 31, 1999 for the underlying
properties, the underlying wells, the underlying leases, a subtotal and the net
profits interests. The Ryder Scott reserve reports are included as Exhibits A
and B to this prospectus. The quantities reflected under the column subtotal in
the table below represent 80% of reserves attributable to the underlying wells
and 10% of reserves attributable to the underlying leases before deducting
reserve quantities sufficient to pay $0.05 per Mcfe for office expenditures,
information systems and other capitalized costs which are included in production
costs and $0.14 per Mcfe for reimbursement for depreciation and to provide a
return on investment of Eastern States' gathering and compression systems. For a
further description of the computation of net proceeds, see "Computation of Net
Proceeds -- Net Profits Interests."

UNDERLYING UNDERLYING UNDERLYING NET PROFITS
PROPERTIES(100%) WELLS(80%) LEASES(10%) SUBTOTAL INTERESTS
----------------- ---------- ----------- -------- -----------
($ IN THOUSANDS)

Proved developed reserves
Natural gas (MMcf)................ 329,581 263,665 -- 263,665 210,018
Oil (MBbls)....................... 260 208 -- 208 171
Natural gas equivalents (MMcfe)... 331,139 264,911 -- 264,911 211,044
Proved undeveloped reserves
Natural gas (MMcf)................ 436,533 -- 43,653 43,653 29,083
Oil (MBbls)....................... -- -- -- -- --
Natural gas equivalents (MMcfe)... 436,533 -- 43,653 43,653 29,083
Total proved reserves
Natural gas (MMcf)................ 766,114 263,665 43,653 307,318 239,101
Oil (MBbls)....................... 260 208 -- 208 171
Natural gas equivalents (MMcfe)... 767,672 264,911 43,653 308,564 240,127
Future net revenues................. $1,470,948 $577,182 $74,947 $652,129 $577,207
Standardized measure of discounted
future net cash flows............. $ 367,277 $211,889 $10,242 $222,131 $200,420

The following table summarizes the changes in proved reserves of the
underlying properties for the periods indicated. The data is presented assuming
the underlying properties were acquired before

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46

December 31, 1995. Reserve estimates for underlying properties that Eastern
States acquired in 1996 and 1997 are not available prior to the date acquired.
For purposes of calculating quantities of proved reserves as of December 31,
1995 and 1996, proved reserves were derived by assuming they equal the reserves
at December 31, 1997, plus production, less positive revisions from drilling by
Eastern States for the years 1996 and 1997. This table does not include any
revisions, extensions or discoveries prior to Eastern States' acquisition of
Blazer Energy on June 30, 1997.

100% UNDERLYING PROPERTIES
--------------------------------------
NATURAL GAS
NATURAL GAS OIL EQUIVALENTS
(MMCF) (MBBLS) (MMCFE)
----------- ---------- -----------

Balance, December 31, 1995............................... 666,996 338 669,024
Revisions, extensions, discoveries and additions...... 6,094 -- 6,094
Production............................................ (19,318) (35) (19,528)
------- --- -------
Balance, December 31, 1996............................... 653,772 303 655,590
Revisions, extensions, discoveries and additions...... 11,167 -- 11,167
Production............................................ (19,960) (31) (20,146)
------- --- -------
Balance, December 31, 1997............................... 644,979 272 646,611
Revisions, extensions, discoveries and additions...... 63,187 20 63,307
Production............................................ (19,040) (20) (19,160)
------- --- -------
Balance, December 31, 1998............................... 689,126 272 690,758
Revisions, extensions, discoveries and additions...... 88,955 7 88,995
Production............................................ (11,967) (19) (12,081)
------- --- -------
Balance, August 31, 1999................................. 766,114 260 767,672
======= === =======
Proved Developed Reserves
Balance, December 31, 1995............................... 360,942 338 362,970
Balance, December 31, 1996............................... 347,718 303 349,536
Balance, December 31, 1997............................... 338,925 272 340,557
Balance, December 31, 1998............................... 344,907 272 346,539
Balance, August 31, 1999................................. 329,581 260 331,139

There are 1,528 proved undeveloped drilling locations in the underlying
leases identified for exploration. Eastern States expects to spend approximately
$44 million per year on development costs for at least the next five years. Of
these development costs, 10% will be attributable to the net profits interests
of the trust.

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

The following table provides the summary calculation of the standardized
measure of discounted future net cash flows of the underlying properties, the
underlying wells, the underlying leases, a subtotal and the net profits
interests as of August 31, 1999. Because the underlying properties and the trust
are not taxable at the underlying property level or trust level, no provision is
included for income taxes.

UNDERLYING UNDERLYING UNDERLYING NET PROFITS
PROPERTIES (100%) WELLS (80%) LEASES (10%) SUBTOTAL INTERESTS
----------------- ----------- ------------ --------- -----------
(IN THOUSANDS)

Future cash flows............. $ 2,129,626 $ 729,285 $121,802 $ 851,087 $ 628,249
Future costs:
Production.................. 373,705 151,881 18,385 170,266 51,042
Development................. 284,973 222 28,470 28,692
----------- --------- -------- --------- ---------
Future net cash flows....... 1,470,948 577,182 74,947 652,129 577,207
10% discount factor......... (1,103,671) (365,293) (64,705) (429,998) (376,787)
----------- --------- -------- --------- ---------
Standardized measure........ $ 367,277 $ 211,889 $ 10,242 $ 222,131 $ 200,420
=========== ========= ======== ========= =========

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NATURAL GAS SALES PRICES AND PRODUCTION COSTS

The following table sets forth the annual production, the average realized
sales price per Mcf produced and the average production cost per Mcfe for each
of the years ended December 31, 1996, 1997 and 1998 and for the eight-month
period ended August 31, 1999 for the underlying properties on a historical basis
and for the year ended December 31, 1998 and the eight months ended on August
31, 1999 for the net profits interests on a pro forma basis. Pro forma figures
are calculated by attributing 80% of production for the underlying properties to
the net profits interests and assuming gas gathering and compression costs,
production costs, development costs and overhead provided for in the conveyances
were in effect for the periods indicated. Average realized sales price reflected
in the table below generally represents the wellhead price of natural gas which
is net of gathering and compression charges and excludes hedging activity.
Production costs as used in the following table include, for all properties,
production and property taxes and production expenses. Overhead has not been
included as a production cost. Average production costs were calculated on an
Mcfe basis in order to spread the cost over combined oil equivalent production
and natural gas production.

For the net profits interests, development and production costs have been
directly deducted from future cash flows. The remaining production costs are
solely production and property taxes.

PRO FORMA FOR NET PROFITS
HISTORICAL FOR UNDERLYING PROPERTIES INTERESTS
------------------------------------------ ---------------------------
EIGHT MONTHS EIGHT MONTHS
YEAR ENDED DECEMBER 31, ENDED YEAR ENDED ENDED
--------------------------- AUGUST 31, DECEMBER 31, AUGUST 31,
1996 1997 1998 1999 1998 1999
------- ------- ------- ------------ ------------ ------------

Wellhead volumes (MMcf).... 19,318 19,960 19,040 11,967 19,040 11,967
Average realized sales
price per Mcf produced... $ 2.84 $ 2.62 $ 2.20 $ 2.14 $ 2.05 $ 1.99
Average production cost per
Mcfe..................... $ 0.59 $ 0.50 $ 0.39 $ 0.39 $ 0.43 $ 0.44

PRODUCING ACREAGE AND WELL COUNTS

For the following data, "gross" refers to the total wells or acres in which
Eastern States owns a working interest and "net" refers to gross wells
multiplied by the percentage working interest owned by Eastern States. The
number of gross acres shown below does not exclude the acreage attributable to
the excluded wells or excluded leases and other interests.

Underlying Properties

WELLS
--------------
GROSS NET GROSS ACRES NET ACRES
----- ----- ----------- ---------

Brenton District....................................... 560 533 397,000 360,000
Madison District....................................... 583 581 374,000 337,000
Weston District........................................ 661 623 192,000 172,000
Pikeville District..................................... 667 666 262,000 230,000
----- ----- --------- ---------
Total........................................ 2,471 2,403 1,225,000 1,099,000
===== ===== ========= =========

In addition, the number of gross acres reflected in this table excludes
approximately 90,000 acres representing the Rome exploration area, but does not
exclude (1) leases that have been farmed out to third parties and (2) leases or
interests with known transfer or title issues, including all potential coalbed
methane exploration and development rights.

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48

The following is a summary of the number of natural gas wells drilled and
completed by Eastern States on the leases which comprise the underlying
properties during the last three years. There are no wells listed under the year
ended December 31, 1998 and the eight months ended August 31, 1999 because all
wells drilled by Eastern States during this time period are excluded from the
underlying wells because of their limited production history and relatively high
decline profile. This summary does not include wells drilled by Blazer Energy
prior to its acquisition by Eastern States on June 30, 1997. Unless otherwise
indicated, all wells drilled are developmental.

EIGHT MONTHS
YEAR ENDED DECEMBER 31, ENDED
--------------------------------------- AUGUST 31,
1996 1997 1998 1999
----------- ----------- ----------- ------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- ---

Natural Gas Wells....................... 54 53 88 88 -- -- -- --
== === == === == === == ===

Excluded Properties

Natural gas wells drilled on or after January 1, 1998 are not included in
the underlying wells. The following is a summary of the number of these wells:

YEAR ENDED EIGHT MONTHS
DECEMBER 31, ENDED AUGUST 31,
1998 1999
-------------- ----------------
GROSS NET GROSS NET
----- --- ------ ----

Natural Gas Wells......................................... 165 162 114 111
=== === === ===

Reserve estimates for the 273 net wells drilled on or after January 1, 1998
are 96 Bcfe with development costs, before drilling overhead, of $57.5 million.
This results in finding and development costs before drilling overhead of $0.60
per Mcfe. If drilling overhead were included for wells drilled on or after
January 1, 1998, the finding and development costs would have been $0.70 per
Mcfe. The projected finding and development costs, including drilling overhead,
for the year 2000 is $0.64 per Mcfe.

OPERATIONS

All of the wells and properties to which the underlying properties relate
are currently operated by Eastern States, although Eastern States is under no
obligation to continue to serve as the operator for the properties. As operator,
Eastern States is responsible for conducting and directing all operations with
respect to the properties, as permitted and required by, and within the limits
of, any applicable operating agreements, including:

- producing the wells;
- discharging obligations of the joint account;
- holding funds for non-operators;

- maintaining records and filing and furnishing governmental reports;

- conducting drilling, testing, completing, reworking, and plugging
operations; and
- maintaining insurance for the joint account.

With respect to the underlying properties, Eastern States must act as a
reasonably prudent operator would act in the Appalachian Basin under the same or
similar circumstances if it were acting with respect to its own properties.

The trust will be entitled to bring actions against Eastern States to
enforce its rights under the transfer documents. If the trustee fails to bring
an action on behalf of the trust, each unitholder has a statutory right under
the Delaware Business Trust Act to bring a derivative action in the Delaware
Court of Chancery on behalf of the trust to enforce the rights of the trust
under the transfer documents,

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including rights relating to the standard of conduct owed to the trust by
Eastern States with respect to operations relating to the underlying properties.

Due to the criteria utilized in selecting wells to be subject to and
burdened by the net profits interests, the lands upon which the wells subject to
the net profits interests are located will, in many instances, also contain
other wells which did not satisfy the selection criteria and which therefore
will not become subject to the net profits interests. In these instances,
Eastern States will generally serve as the operator for all of the wells located
on lands subject to a particular lease. As the operator of this leased property,
Eastern States will generally have a contractual duty to any other working
interest owners to act as a reasonably prudent operator with respect to the
operations of the leased property.

SALE AND ABANDONMENT OF UNDERLYING PROPERTIES; SALE OF NET PROFITS INTERESTS

Eastern States and any transferees will have the right to abandon any well
or property included in the underlying properties if, in its opinion, the well
or property ceases to produce or is not capable of producing in commercially
paying quantities. Eastern States will typically consider a well not capable of
producing in commercially paying quantities if the well's future monthly
operating expenses are projected to exceed the well's future monthly income.
Eastern States' criteria for determining whether to abandon a well or property
are not mandated by contract but are subject to the reasonably prudent operator
standard described above. Under the applicable state law, Eastern States will be
responsible for plugging and abandoning the wells on the underlying properties
for which it is the operator. The costs incurred to plug and abandon wells that
are subject to the net profits interests will be deducted in calculating net
proceeds payable to the trust. Upon abandonment, that portion of the net profits
interests will be extinguished. Eastern States may also sell a well or property
free of the net profits interest in lieu of the payment of abandonment costs or
delay rentals, provided that the trust receives its attributable percentage of
the net proceeds of any sale. Eastern States does not expect to plug or abandon
any of the underlying wells in the next three years.

Eastern States has the right to sell all or any portion of the underlying
properties without the consent of the trust or the unitholders; however, the
purchaser of any of the underlying properties will acquire the underlying
properties subject to the net profits interests relating thereto, except under
the circumstances described below where the trust may be required to release the
net profits interests, subject to its receipt of the fair value thereof. Upon
the transfer of all or a portion of the underlying properties, Eastern States
may retain the right to operate the underlying properties subject to the net
profits interest and the terms of the transfer documents. Following a transfer,
the underlying properties will continue to be subject to the net profits
interests, and the net proceeds attributable to the transferred property will be
calculated separately and paid by the transferee. The transfer documents will be
recorded in the appropriate real property records to give notice of the net
profits interests to Eastern States' creditors and transferees. In accordance
with the transfer documents any purchaser will be subject to the standard of a
reasonably prudent operator in the Appalachian Basin with respect to
development, operation and abandonment of the underlying properties. A
transferee of the underlying properties, by virtue of the transfer, may be
obligated to file reports under the Securities Exchange Act of 1934.

Upon notice from Eastern States, the trust is required to sell, for cash,
net profits interests related to underlying properties which Eastern States is
selling to an unaffiliated party. These types of sales may not exceed $3 million
in any calendar year or $20 million on an aggregate basis for the life of the
trust. Under these circumstances, the trust will receive:

- 80% of the net proceeds from the sale of any of the 2,471 underlying
wells; and

- 10% of the net proceeds from the sale of any of the underlying leases or
the sale of any well drilled on the underlying leases on or after
September 1, 1999.

In addition, as an owner of the underlying properties, Eastern States may
enter into farmout, operating, participation and other similar agreements
covering the property. The net profits interest held by the trust would then be
calculated on the interest retained by Eastern States under the agreement and
not on Eastern States' or the trust's original interest before modification by
the agreement. Eastern States may

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enter into any of these agreements without the consent or approval of the
trustee or any trust unitholder. However, Eastern States' interest in entering
into any of these types of agreements should be parallel with that of trust
unitholders because Eastern States is retaining 20% of the net profits interest
in the 2,471 underlying wells and 90% of the net profits interest in all wells
drilled on the underlying leases on or after September 1, 1999. Immediately
after this offering, Eastern States will also own up to 25% of the outstanding
trust units.

GAS PURCHASE CONTRACTS

Eastern States will market the natural gas produced from the underlying
properties. Although it is not contractually obligated to do so, Eastern States
will attempt to obtain the best prices available to it in the marketplace.
Generally, natural gas produced from the underlying properties will be sold by
Eastern States under existing contracts that have market-based terms. Eastern
States currently has significant contracts with affiliates of CNG Transmission
Corp and its own affiliate, Statoil Energy Services, Inc. Each of these
contracts expire in October 2000. The trustee has the right under the trust
agreement to review the charges under the gas purchase contracts.

In 1998, approximately 90% of the natural gas produced by Eastern States
was sold under these contracts. For the eight-month period ended August 31,
1999, approximately 68% of Eastern States' natural gas production was sold to
Statoil Energy Services and approximately 22% was sold to affiliates of CNG
Transmission Corp.

Under the CNG contracts, affiliates of CNG purchase natural gas from
Eastern States based on the terms contained in confirmations which the parties
enter into from time to time. The CNG confirmations contain the following:

- quantity;
- price;
- delivery point; and
- effective period of the confirmation.

The price under the CNG contracts is based on the published price of Inside
FERC-Appalachian Basin for CNG on an MMbtu basis, plus a $0.02 per MMbtu
premium, less applicable gathering, compression and processing fees. The price
for the natural gas is inclusive of all taxes levied on production or
transportation of the natural gas up to the delivery point. Payment from CNG
affiliates is due by the 55th day following delivery.

Each CNG confirmation sets forth the quantity of natural gas to be
delivered by Eastern States to the delivery point. The delivery point is, in
general, the point of the interconnection of Eastern States' gathering
facilities with the metering facilities of CNG's interstate transmission or
gathering pipeline system. Eastern States is responsible for delivery of natural
gas to the delivery point. Title and risk of loss to the natural gas pass to the
CNG affiliate at the delivery point. Each CNG confirmation sets forth the period
of time that the terms of the confirmation are effective. The effective period
of a confirmation with the CNG affiliates has typically been for 12 months.

The contract with Statoil Energy Services is also based on the terms
contained in confirmations which the parties enter into from time to time. These
confirmations contain the same information as the CNG confirmations discussed
above.

The price under the Statoil Energy Services contract is based on the
published price of Inside FERC -- Appalachian Basin for Columbia Gas
Transmission Corp., for natural gas delivered into Columbia Gas Transmission's
interstate transmission pipeline system, on an MMbtu basis, plus a $0.02 per
MMbtu premium, less gathering, compression and processing fees. Eastern States
is responsible for all taxes attributable to the natural gas before the delivery
point. Statoil Energy Services is responsible for all taxes attributable to the
natural gas after the delivery point. Title and risk of loss pass to Statoil
Energy Services at the delivery point. Payment is due from Statoil Energy
Services by the 55th day following delivery.

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Eastern States has historically sold its natural gas on the spot market,
i.e., contracts of one year or less. However, Eastern States may enter into
longer term contracts in the future.

HEDGING ACTIVITIES

Eastern States has historically entered into hedging contracts with respect
to its natural gas production at specified prices for a specified period of
time. As described under the caption "Projected Year 2000 Distributable Cash"
that begins on page 25, Eastern States has agreed to hedge the trust's share of
year 2000 production from the underlying properties under a so-called "collar"
arrangement. Eastern States has eliminated its exposure to this "collar"
arrangement by entering into a comparable agreement with a third party. After
the closing of this offering, Eastern States may continue to enter into hedging
contracts with respect to natural gas production from the underlying properties
only for the portion of natural gas that is attributable to its retained
interests. For example, Eastern States may enter into hedging contracts for up
to 20% of the production from the 2,471 underlying wells and up to 90% of the
production from wells drilled on the underlying leases after the closing of this
offering. Except for Eastern States obligations under the "collar" arrangement,
any gains or losses from Eastern States' other hedging activities will not
affect amounts paid to the trust. Long-term contracts for the physical sale and
delivery in the future of natural gas volumes are not hedging contracts.

REGULATION

Natural Gas Regulation. The availability, terms and cost of transportation
significantly affect sales of natural gas. The interstate transportation and
sale for resale of natural gas is subject to federal regulation, including
transportation rates, storage tariffs and various other matters, primarily by
the Federal Energy Regulatory Commission. Federal and state regulations govern
the price and terms for access to natural gas pipeline transportation. The
Federal Energy Regulatory Commission's regulations for interstate natural gas
transmission in some circumstances may also affect the intrastate transportation
of natural gas.

While natural gas prices are currently unregulated, Congress historically
has been active in the area of natural gas regulation. Eastern States cannot
predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state
legislatures, and what effect, if any, the proposals might have on the
operations of the underlying properties.

Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices. The Federal Energy Regulatory
Commission implemented regulations on January 1, 1995, to establish an indexing
system for transportation rates for oil that could increase the cost of
transporting oil to the purchaser.

Eastern States' gathering operations are subject to occupational safety,
health and operational regulations relating to the design, installation,
testing, construction, operation, replacement and management of facilities.
Pipeline safety issues have recently been the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels. Eastern States believes that its operations, to the extent they may be
subject to current natural gas pipeline safety or other health and safety
requirements, comply in all material respects with these requirements.

Eastern States is not able to predict what effect, if any, these
regulations might have.

Environmental Regulation. Companies that are engaged in the oil and gas
industry are affected by federal, state and local laws regulating the discharge
of materials into the environment or otherwise relating to environmental
protection. Eastern States believes that it is in substantial compliance with
the environmental laws and regulations that apply to the operations of the
underlying properties. Eastern States has not previously incurred material
expenses in complying with environmental laws and regulations that affect its
operations of the underlying properties and does not currently expect that
future compliance will have a material adverse effect on the trust or the
quarterly distributions. For a detailed description of the environmental
regulations applicable to Eastern States, see Appendix A "Information About
Eastern States Oil & Gas, Inc. -- Business and Properties -- Environmental
Matters."

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State Regulation. The states of Kentucky and West Virginia may regulate the
production, gathering and sale of oil and natural gas, including imposing
requirements for obtaining drilling permits, the method of developing new
fields, the spacing and operation of wells and the prevention of waste of oil
and gas resources. These states may also regulate rates of production, may
establish maximum daily production allowables from both oil and gas wells based
on market demand or resource conservation, or both, and may require that certain
wells be shut-in.

The states of Kentucky and West Virginia also regulate the service which is
provided to customers by Eastern States in connection with the direct supply of
natural gas to homeowners.

The petroleum industry is also subject to compliance with various other
federal, state and local regulations and laws. Some of those laws relate to
occupational safety, resource conservation and equal employment opportunity.
Eastern States does not believe that compliance with these laws will have a
material adverse effect upon the trust unitholders.

TITLE TO PROPERTIES

Eastern States believes that its title to the underlying properties is, and
the trust's title to the net profits interest will be, good and defensible
according to the standards generally accepted in the Appalachian Basin oil and
gas industry. "Good and defensible title" means record ownership of oil and
natural gas leasehold rights which afford the owner with the right to explore
for, drill and produce oil and natural gas from the property.

The underlying properties are typically subject, in one degree or another,
to one or more of the following:

- royalties, overriding royalties and other burdens under oil and gas
leases;

- relocation provisions under oil and gas leases with coal mining entities;
- contractual obligations, including, in some cases, development
obligations, arising under operating agreements, farmout agreements,
production sales contracts and other agreements that may affect the
properties or their titles;
- liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing unpaid suppliers and contractors
and contractual liens under operating agreements;

- pooling, unitization and communitization agreements, declarations and
orders; and

- easements, restrictions, rights-of-way and other matters that commonly
affect property.

To the extent that these burdens and obligations affect Eastern States'
rights to production and the value of production from the underlying properties,
they have been taken into account in calculating the trust's interests and in
estimating the size and the value of the reserves attributable to the net
profits interests. Eastern States believes that the burdens and obligations
affecting the underlying properties and the net profits interests are
conventional in the industry for similar properties. Eastern States also
believes that the burdens and obligations do not in the aggregate materially
interfere with the use of the underlying properties and will not materially
adversely affect the value of the net profits interests.

Although the matter is not entirely free from doubt, Eastern States
believes that the net profits interests should constitute real property
interests under Kentucky law, but not under West Virginia law. Under West
Virginia law, however, it is likely, although not entirely certain, that a net
profits interest constitutes an economic interest in gross production measured
by net profits, and that title to the economic interests can be transferred by a
transfer document. Nevertheless, Eastern States will record the conveyances in
the appropriate real property records of Kentucky and West Virginia. If during
the term of the trust, Eastern States should become a debtor in a bankruptcy
proceeding, it is not entirely certain that the net profits interests would be
treated as real property interests under the laws of Kentucky, and they would
not be so treated under West Virginia law. If a determination were made in a
bankruptcy proceeding that a net profits interest did not constitute a real
property interest or a transferable economic interest under applicable state
law, it could be designated an executory contract. An executory contract is a
term used, but not defined, in the federal bankruptcy code to refer to a
contract under which the

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obligations of both the debtor and the other party are so unsatisfied that the
failure of either to complete performance would constitute a material breach
excusing performance by the other. If a net profits interest were designated an
executory contract and rejected in the bankruptcy proceeding, Eastern States
would not be required to perform its obligations under the net profits interest
and the trust would seek damages as one of Eastern States' unsecured creditors.
Although no assurance can be given, Eastern States believes that the net profits
interests should not be subject to rejection in a bankruptcy proceeding as
executory contracts.

YEAR 2000

"Year 2000," or the ability of computer systems to process dates with years
beyond 1999, affects almost all companies and organizations. Computer systems
that are not Year 2000 compliant by January 1, 2000 may cause material adverse
effects to companies and organizations that rely upon those systems. The trust's
timely receipt of royalty income and disbursement of distributable income to
trust unitholders will largely depend upon performance of computer systems of
Eastern States, the trust's transfer agent and other third parties. These third
parties include oil and natural gas purchasers and significant service providers
such as electric utility companies and natural gas plant, pipeline and gathering
system operators.

Eastern States has reviewed its computer systems and is making the
necessary modifications for Year 2000 compliance. Eastern States is completing
modifications and testing of its land computer programs and expects to complete
remediation and testing by the end of November 1999. The remaining computer
systems have been assessed and are believed to be compliant.

Some of Eastern States' critical field equipment, such as natural gas
compressors, are partially controlled or regulated by embedded computer chips.
Based on a preliminary review of all operating areas, Eastern States has
identified no significant compliance exceptions. Based on its review,
remediation efforts and the results of testing, Eastern States does not believe
that timely modification of its computer systems for Year 2000 compliance
represents a material risk to the trust. Eastern States estimates that total
costs related to Year 2000 compliance efforts will be approximately $200,000 of
which approximately $130,000 has been incurred and expensed through September
30, 1999. The trust will not incur any of Eastern States' Year 2000 costs.

Eastern States has identified significant third parties whose Year 2000
compliance could affect Eastern States and has formally inquired about their
Year 2000 status. Eastern States has received responses to all of its inquiries.
All respondents have indicated that they will be Year 2000 compliant by January
1, 2000. In addition, the property trustee and its primary service provider for
trust distributions and account maintenance have indicated that they will be
Year 2000 compliant by January 1, 2000. Despite its efforts to assure that the
third parties are Year 2000 compliant, Eastern States cannot provide assurance
that all significant third parties will achieve compliance in a timely manner. A
third party's failure to achieve Year 2000 compliance could have a material
adverse effect on Eastern States' operations and cash flow, and therefore have a
material adverse impact on timely trust distributions to trust unitholders. For
example a third party might fail to deliver revenue related to the trust's net
profits interest to Eastern States, or Eastern States might fail to deliver the
income of the net profits interest to the trust. In these situations, the
trustee would be unable to make distributions of those amounts to trust
unitholders on a timely basis.

Eastern States has prepared contingency plans in the event of any potential
problems resulting from failure of Eastern States' or significant third party
computer systems and compressors on January 1, 2000. As part of its contingency
plans, Eastern States will have certain key employees working on both December
31, 1999 and January 1, 2000 to determine that Eastern States' computer systems
and compressors continue to operate normally. Eastern States anticipates minimal
problems will be encountered which would affect trust assets, but the most
reasonably likely worst scenario is the loss of production from 10% to 20% of
the underlying wells for several days in January 2000 due to compressors not
properly functioning. Such loss is estimated to be less than 1% of projected
year 2000 revenue.

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LITIGATION

Various legal actions that have arisen in the ordinary course of business
are pending with respect to Eastern States and its affiliates. None of these
proceedings would reasonably be expected to have a material adverse impact on
Eastern States' results of operations or financial position.

Any liability relating to the underlying properties prior to September 1,
1999 will be borne by Eastern States. Any liabilities relating to the underlying
properties on or after September 1, 1999 could proportionately reduce the amount
of net proceeds payable to the trust based on the percentage of the trust's net
profits interests.

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COMPUTATION OF NET PROCEEDS

The provisions governing the computation of the net proceeds are detailed
and extensive. The following describes all of the material terms of the net
profits interests but the computation of net proceeds is subject to and
qualified by the more detailed provisions of the transfer documents of the net
profits interests that are filed as exhibits to the registration statement. You
should review those exhibits before making an investment in the trust units. See
"Available Information" which describes how you may obtain copies of those
exhibits.

NET PROFITS INTERESTS

The net profits interests are defined net profits interests carved from the
underlying properties. The net profits interests entitle the trust to receive
80% of the net proceeds from the sale of natural gas produced from the 2,471
underlying wells and 10% of the net proceeds from the sale of natural gas
produced from wells drilled by Eastern States on the underlying leases on or
after September 1, 1999.

The underlying properties are adjacent, in some cases, to other properties
in which Eastern States has an interest and which generally produce from the
same formations and horizons as the wells included in the underlying properties.
The trust will not receive a net profits interest in the net proceeds from the
sale of natural gas from these excluded properties.

The amounts paid to the trust for the net profits interests are based on
the definition of "net proceeds" contained in the transfer documents and
described below. Under the transfer documents, net proceeds are computed
quarterly on a state-by-state basis. Eastern States pays the net proceeds
attributable to a computation period to the trust on or before the 20th day of
the third calendar month following the end of each calendar quarter. Eastern
States will not pay to the trust interest on the net proceeds held by Eastern
States prior to payment to the trust. The property trustee makes quarterly
distributions to trust unitholders. For a description of the terms of the trust
agreement pertaining to cash distributions, see "Description of the Trust
Units -- Distributions and Income Computations."

Net proceeds payable to the trust equal the excess of aggregate gross
proceeds over aggregate costs. For the trust's share of year 2000 production
from the underlying properties, Eastern States has agreed to a hedge for the
benefit of the trust. Under such hedge agreement, Eastern States has agreed that
if the monthly closing NYMEX price for year 2000 natural gas production during
any month is less than the "floor" price of $ per MMbtu or more than the
"ceiling" price of $ per MMbtu, the net proceeds payable to the trust for
such production will be calculated as if the monthly closing NYMEX price for
such month was $ per MMbtu or $ per MMbtu, respectively. The net
proceeds of the trust attributable to the trust's share of production for any
period other than year 2000 will not be calculated upon any hedge, collar or
other derivative agreement entered into by Eastern States.

Aggregate gross proceeds means 80% of the gross proceeds attributable to
the underlying wells plus 10% of the gross proceeds attributable to wells
drilled on the underlying leases on or after September 1, 1999. Aggregate costs
means 80% of the costs attributable to the underlying wells plus 10% of the
costs attributable to the wells drilled on the underlying leases on or after
September 1, 1999, plus excess costs as of the end of the prior computation
period, plus interest on the amount of excess costs as of the end of the prior
computation period calculated at the prime rate for the current computation
period.

Gross proceeds means the amounts received by Eastern States from sales of
natural gas and oil produced from the underlying properties. The following are
excluded from the calculation of gross proceeds:

- all general property (ad valorem), production, severance, sales,
gathering, excise and other taxes (other than income taxes) and gathering
and compression costs if they are deducted or excluded from the proceeds
of sales of production;

- any amount attributable to nonconsent operations conducted on the
underlying properties as to which Eastern States is a nonconsenting party
and which is dedicated to the recoupment or reimbursement of costs and
expenses of the consenting party by the terms of the relevant

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agreement providing for the nonconsent operations has exercised its right
under the applicable operating or other agreements not to consent to
payment of expenses for activities conducted by other working interest
owners;

- any amount for natural gas lost in the production or marketing thereof or
used for drilling, production or plant operations conducted for the
purpose of drilling for, producing, processing or marketing natural gas
from the underlying properties;
- any payment made to the owner of an underlying property for:

-- payments for the sale or transfer of the underlying properties (subject
to the net profits interest);

-- payments for the sale of equipment or other personal property,
fixtures, gathering systems and other tangible property located on the
underlying properties or used in connection therewith;

-- natural gas not taken, but to the extent payments are allocated to
natural gas taken in the future, payments are included, without
interest, in gross proceeds when the natural gas is taken;

-- damages, other than drainage or reservoir injury;

-- rental for reservoir use; and

-- payments in connection with the drilling of any well.

Gross proceeds includes payments for future production if they are not
subject to repayment in the event of insufficient subsequent production. Gross
proceeds also includes cash payments received by the owner of the underlying
properties in respect of any lease or farmout of the underlying properties.

Costs mean, on a cash basis, generally the sum of:

- all payments to mineral or land owners, such as royalties or other
burdens against production, delay rentals, shut-in natural gas payments,
minimum royalty or other payments for drilling or deferring drilling;

- any taxes other than income taxes to the extent not previously deducted
in calculating gross proceeds, including estimated and accrued ad valorem
and other property and production taxes;

- all development costs, which include all costs, expenses and liabilities
of exploring, drilling and reworking natural gas wells, including
allocated expenses such as labor, vehicle and travel costs and materials;

- seismic, geophysical and other exploration costs;
- third party costs and charges associated with gathering, compressing and
processing natural gas;

- Eastern States' costs and charges associated with gathering, compressing
and processing natural gas, plus reimbursement for depreciation and a
return on investment;

- plugging and abandonment costs;

- overhead charges, which include a producing well fixed fee, a fixed per
well general and administrative fee and a fixed per well fee for wells
drilled or deepened;

- costs of insurance, if any, pertaining to the ownership or operation of
the underlying properties;

- costs of any litigation pertaining to the underlying properties arising
from activities conducted after September 1, 1999, including settlements,
damages, refunds, fines, interest and penalties paid to third parties or
governmental authorities, provided that the owner of the underlying
properties has acted as a reasonably prudent operator;

- amounts previously included in gross proceeds but subsequently paid as a
refund, interest or penalty;
- costs and expenses for renewals or extensions of leases; and

- at the option of the owner of an underlying property, accruals for costs
approved under authorizations for expenditure and prepayment of costs
reasonably expected to be incurred within 180 days of the quarter in
which the prepayment is made.

Effective September 1, 1999, Eastern States will deduct costs when
calculating the net proceeds that it has not previously charged or, in some
cases, deduct higher costs than what it had previously charged. These costs were
not charged in the past because Eastern States owns approximately a 97% working

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interest in the properties subject to the net profits interest and would,
therefore, bear substantially all of the costs. When calculating net proceeds,
Eastern States will proportionately reduce these costs based on the trust's
percentage net profits interests. These costs are set forth in the transfer
documents and include the following:

Production Costs. As payment for operating the wells included in the
underlying properties, except for wells producing below 7,000 feet, Eastern
States will deduct a monthly fixed production fee of $170 per well for those
wells producing five or more Mcf per day on an annual basis and $70 per well for
those wells producing less than five Mcf per day on an annual basis. For those
wells completed at depths below 7,000 feet, Eastern States will deduct a monthly
fixed production fee of $300 per well. Wells that are shut-in, temporarily
abandoned or otherwise inactive for mechanical reasons or pipeline constraints
or because they may no longer be economic to continue to produce will be charged
the applicable monthly fixed production cost if they are completed in a zone
above 7,000 feet and $300 if they are completed in a zone below 7,000 feet. The
monthly fixed production cost will no longer be charged once a well is plugged
and abandoned. Each of these fixed production costs is subject to an annual
adjustment beginning April 1, 2001 in accordance with an industry standard set
forth in the accounting procedures in the transfer documents. Approximately 85%
of the 2,471 underlying wells are currently producing in excess of an average of
five Mcf per day. Production costs will be proportionately reduced based on
Eastern States' percentage working interest in the applicable well.

Eastern States Gathering and Compressing Charges. Eastern States will
deduct from gross proceeds an amount equal to its costs incurred to gather,
compress and process production from the underlying properties on Eastern
States' facilities plus an amount to reimburse Eastern States for depreciation
of the facilities and to provide a reasonable return on its investment in such
facilities. The amount of this charge will vary as changes occur in Eastern
States' investment in facilities associated with the underlying properties, as
well as when changes occur in the costs incurred by Eastern States to perform
such services.

Overhead. Generally, fees are allocated among operating and non-operating
interests. Because Eastern States has historically owned and operated almost
100% of its properties, it has not charged or allocated an overhead fee to the
non-operator. Pursuant to the transfer documents, Eastern States will deduct a
monthly overhead fee of $65 per producing well from the underlying properties,
including shut-in wells, subject to an annual adjustment beginning April 1, 2001
in accordance with an industry standard set forth in the accounting procedures
in the transfer documents. This fee will no longer be charged once a well is
plugged and abandoned. This fee will be proportionately reduced based on Eastern
States' percentage working interest in the applicable well.

Development Costs and Drilling Overhead. Eastern States will deduct all
development costs in calculating net proceeds attributable to the underlying
properties, plus a drilling overhead fee of $36,000 for each well drilled or
deepened to a deeper zone on or after September 1, 1999, subject to an annual
adjustment beginning April 1, 2001 in accordance with an industry standard set
forth in the accounting procedures in the transfer documents. Drilling costs
will fluctuate seasonally as a result of Eastern States' weather-related
concentration of drilling activity in the period from April to October. The
drilling overhead fee will be proportionately reduced based on Eastern States'
percentage working interest in the applicable well.

Excess costs are the excess of costs over gross proceeds, plus interest
accrued on such excess amount at the prime rate. Therefore, if costs exceed
gross proceeds for a computation period, the trust will receive no payment for
that period, and excess costs, plus interest accrued at the prime rate, will be
carried over to the following month as a cost in determining the excess of gross
proceeds over costs for that following month.

Gross proceeds and costs are calculated on a cash basis, except that some
costs, primarily ad valorem taxes and expenditures of a material amount, may be
determined on an accrual basis. For convenience in complying with state tax
laws, the net profits interests were created by two separate transfer documents,
one for each of Kentucky and West Virginia, the two states in which the
underlying properties are located.

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Net proceeds are calculated separately for the underlying properties covered by
each transfer document, so excess costs in one state do not reduce net proceeds
from the other.

Any gains or losses from hedging activities by Eastern States will not
affect the calculation of net proceeds.

ADDITIONAL PROVISIONS

The trust is not liable to the owner of the underlying properties or the
operators for any operating, capital or other costs or liabilities attributable
to the underlying properties. The trustee is not obligated to return any cash
received from the net profits interests. Any overpayments made to the trust due
to adjustments to prior calculations of net proceeds or otherwise will reduce
future amounts payable to the trust until Eastern States recovers the
overpayments plus interest at the prime rate.

Eastern States must maintain books and records sufficient to determine the
amounts payable for the net profits interests. Quarterly and annually, Eastern
States must deliver to the trustee a statement of the computation of the net
proceeds for each computation period. Eastern States will cause the annual
computation of net proceeds to be audited. The audit cost will be borne by the
trust.

As discussed under "The Underlying Properties -- Sale and Abandonment of
Underlying Properties; Sale of Net Profits Interests," Eastern States may convey
any or all of the underlying properties without the consent of the trust or the
unitholders. In this case, the trust's net profits interest must be paid by the
transferee to the extent attributable to the underlying properties transferred.
Neither the trust nor the unitholders are entitled to any of the proceeds from
any sale of the underlying properties. If, however, the net profits interests
are sold with the underlying properties, the trust will receive the proceeds
attributable to the sale of its net profits interests.

FEDERAL INCOME TAX CONSEQUENCES

This section discusses all the material federal income tax consequences of
the ownership and sale of trust units. Many aspects of federal income taxation
that may be relevant to a particular taxpayer or to some types of taxpayers
subject to specific tax treatment are not addressed. In addition, the tax laws
can and do change regularly, and any future changes could have an adverse effect
on the ownership or sale of trust units. The trust will not request rulings from
the IRS dealing with the tax consequences of ownership of trust units. Instead
the trust will rely on the opinion of Andrews & Kurth L.L.P. regarding the
classification of the trust and the federal income tax consequences described
below. Andrews & Kurth L.L.P. believes that its opinion is in accordance with
the present position of the IRS regarding grantor trusts. The opinion is not
binding on the IRS or the courts, however, and no assurance can be given that
the IRS or the courts will agree with it.

This discussion is based on current provisions of the Internal Revenue
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 Internal
Revenue Code have not been interpreted by the courts or the IRS. Currently
pending proposed Federal tax legislation may also, under certain circumstances,
have a material effect on a unitholder.

As a consequence, each prospective unitholder should consult his own tax
advisor with respect to his particular circumstances including his alternative
minimum tax circumstances.

SUMMARY OF LEGAL OPINIONS

Andrews & Kurth L.L.P. is of the opinion that, for federal income tax
purposes:

- the trust will be treated as a grantor trust and not as a partnership or
a corporation; and
- the income from the net profits interests will be royalty income subject
to an allowance for depletion.

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Andrews & Kurth L.L.P. advises that, unless noted otherwise, legal
conclusions stated in this section constitute its opinion.

Because no ruling is being requested from the IRS with respect to the trust
or trust unitholders, the IRS could challenge these opinions and statements,
which do not bind the IRS or the courts. The IRS could win in court if it did
challenge these matters.

CLASSIFICATION AND TAXATION OF THE TRUST

In the opinion of Andrews & Kurth L.L.P., under current law, the trust will
be taxable as a grantor trust. As a grantor trust, the trust will not be subject
to tax at the trust level. For tax purposes, the grantors, who in this case are
the trust unitholders, will be considered to own the trust's income and
principal as though no trust were in existence. A grantor trust simply files an
information return, reporting all items of income or deduction which must be
included in the tax returns of the trust unitholders based on their respective
accounting methods and taxable years without regard to the accounting method and
tax year of the trust. If, contrary to the opinion of Andrews & Kurth L.L.P.,
the trust were determined to be a business entity, it would be taxable as a
partnership unless it elected to be taxed as a corporation. The principal tax
consequence of the trust's being treated as a partnership would be that all
trust unitholders would report their share of income from the trust on the
accrual method of accounting regardless of their own method of accounting.

DIRECT TAXATION OF TRUST UNITHOLDERS

Because the trust will be treated as a grantor trust for federal income tax
purposes, each trust unitholder will be taxed directly on his share of trust
income and will be entitled to claim his share of trust deductions. Each trust
unitholder will recognize taxable income when the trust receives or accrues it,
even if it is not distributed until later. Trust unitholders will report their
share of trust income and expenses consistent with their own method of
accounting and their own tax year.

REPORTING OF TRUST INCOME AND EXPENSES

The trust will make quarterly distributions to unitholders of record on
each quarterly record date established for that distribution. The terms of the
trust agreement, as described below, seek to assure to the extent practicable
that income attributable to distributions will be reported to the unitholder who
receives the distributions, assuming that he is the owner of record on the
quarterly record date established for the distribution. However, a unitholder
will not receive the cash giving rise to that income in all situations. 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 liability must be reported by the unitholder, even
though that cash is not distributed to him.

The trust will allocate income and deductions to unitholders based on
record ownership at quarterly record dates established for distributions to the
unitholders. The impact of this allocation method will be to treat the taxable
income of the trust for a particular quarter as income to unitholders of record
for that quarter unless otherwise advised by counsel. It is unknown whether the
IRS will accept that allocation or will seek to require income and deductions of
the trust to be determined and allocated daily or on some other basis, possibly
retroactively to the date of the consummation of this offering. If the IRS were
successful in doing so, trust income might be taxed to trust unitholders other
than those who received the distribution relating to that income. Also, an
accrual basis trust unitholder might realize royalty income in a tax year
earlier than that reported by the trustee.

ROYALTY INCOME AND DEPLETION

In the opinion of Andrews & Kurth L.L.P. the income from the net profits
interests will be royalty income qualifying for an allowance for depletion. The
depletion allowance must be computed separately by each trust unitholder for
each oil or gas property, within the meaning of Section 614 of the Internal
Revenue Code. Andrews & Kurth L.L.P. understands that the IRS is presently
taking the position that a
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net profits interest carved from multiple properties is a single property for
depletion purposes. Accordingly, the trust intends to take the position that
each net profits interest transferred to the trust by a conveyance is a single
property for depletion purposes. The trust will change this position if a
different method is established by the IRS or the courts.

The deduction for depletion is determined annually and is the greater of
cost depletion or, if allowable, percentage depletion. Royalty income from
production attributable to trust units owned by independent producers will
qualify for percentage depletion. An individual or entity with production of the
equivalent of not more than 1,000 barrels of oil per day is an independent
producer. Percentage depletion is a statutory allowance equal to 15% of the
gross income from production from a property. Percentage depletion is subject to
a net income limitation of 100% of the taxable income from the property,
computed without regard to depletion deductions and some loss carrybacks. The
depletion deduction attributable to percentage depletion for a taxable year is
limited to 65% of the taxpayer's taxable income for the year before allowance of
independent producers percentage depletion and some loss carrybacks. Unlike cost
depletion, percentage depletion is not limited to the adjusted tax basis of the
property, although it reduces the adjusted tax basis, but not below zero.

Eastern States believes that trust unitholders who purchase trust units in
this offering will derive a substantially greater benefit from cost depletion
than from percentage depletion.

In computing cost depletion for each property for any year, the allowance
for the property is calculated by dividing the adjusted tax basis of the
property at the beginning of the year by the estimated total number of Bbls of
oil or Mcf of natural gas recoverable from the property. This amount is then
multiplied by the number of Bbls of oil or Mcf of natural gas produced and sold
from the property during the year. Cost depletion for a property cannot exceed
the adjusted tax basis of the property. Each trust unitholder will compute cost
depletion using his basis in his trust units. Information will be provided to
each trust unitholder reflecting how his basis should be allocated among each
property represented by his trust units. To the extent the depletion deduction
exceeds cash distributions per trust unit, that excess can be deducted from the
taxpayer's other sources of taxable income.

OTHER INCOME AND EXPENSES

It is anticipated that the trust's only other income will be interest
income earned on funds held as a reserve or pending distribution. Other trust
expenses will include any state and local taxes imposed on the trust and
administrative expenses of the trustee. Although the issue has not been finally
resolved, Andrews & Kurth L.L.P. believes that all or substantially all of those
expenses are deductible in computing adjusted gross income and, therefore, are
not the type of miscellaneous itemized deductions that are allowable only to the
extent that they total more than 2% of adjusted gross income.

ALTERNATIVE MINIMUM TAX

All taxpayers are subject to an alternative minimum tax. Alternative
minimum taxable income is the taxpayer's taxable income recomputed with various
adjustments plus items of tax preference. In the case of persons other than
independent producers, tax preferences include the excess of percentage
depletion deductions for an oil or natural gas property over the adjusted tax
basis of the property. Alternative minimum tax is the excess of a taxpayer's
tentative minimum tax on his alternative minimum taxable income for a tax year
over his regular tax for that year.

Because the effect of the alternate minimum tax varies depending upon each
trust unitholder's personal tax and financial position, each prospective
investor is advised to consult with his own tax advisor concerning the effect of
the alternate minimum tax on him.

UNRELATED BUSINESS TAXABLE INCOME

Some organizations that are generally exempt from tax under Internal
Revenue Code Section 501 are subject to tax on some types of business income
defined in Section 512 as unrelated business income. In

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the opinion of Andrews & Kurth L.L.P., the income of the trust will not be
unrelated business taxable income so long as the trust does not incur any debt
and the trust units are not debt-financed property within the meaning of Section
514(b). In general, a trust unit would be debt-financed only if the trust
unitholder incurs debt to acquire a trust unit or otherwise incurs or maintains
a debt that would not have been incurred or maintained if the trust unit had not
been acquired.

SALE OF TRUST UNITS

Generally, a trust unitholder will realize gain or loss on the sale or
exchange of his trust units measured by the difference between the amount
realized on the sale or exchange and his adjusted basis for the trust units.
Except to the extent of the depletion recapture amount described below, gain or
loss on the sale of trust units by a trust unitholder who is not a dealer of the
trust units will be a long-term capital gain, taxable at a maximum rate of 20%,
if the trust units have been held for more than 12 months. A trust unitholder's
initial basis in his trust units will be equal to the amount he paid for the
trust units. That basis will be reduced by deductions for depletion claimed by
the trust unitholder, but not below zero.

Upon the sale of the trust units, a trust unitholder must treat as ordinary
income his depletion recapture amount, which is an amount equal to the lesser of
the gain on the sale or the sum of the prior depletion deductions taken on the
trust units, but not in excess of the initial basis of the trust units. The IRS
could also take the position that a portion of the sales proceeds is ordinary
income to the extent of any accrued income at the time of the sale that was
allocable to the trust units sold even though the income had not been
distributed to the selling trust unitholder.

SALE OF NET PROFITS INTERESTS

A sale by the trust of a net profits interest will be treated for federal
income tax purposes as a sale of that net profits interest by the unitholder.
Thus, a unitholder will recognize gain or loss on a sale of a net profits
interest by the trust. A portion of that income will be treated as ordinary
income to the extent of depletion recapture.

TAXATION OF FOREIGN HOLDERS

Unless the election described below is made, a foreign holder, consisting
of a nonresident alien individual, foreign corporation, or foreign estate or
trust, will be subject to federal income withholding tax on his share of gross
royalty income from the net profits interests. The withholding tax will be at a
30% rate, or lower treaty rate if applicable and proper evidence is supplied to
the withholding agent, without any deductions. Gain realized on a sale of a
trust unit by a foreign holder will be subject to federal income tax only if:

- the gain is otherwise effectively connected with business conducted by
the foreign holder in the United States;
- the foreign holder is an individual who is present in the United States
for at least 183 days in the year of the sale;
- the foreign holder has at any time during the five-year period ending on
the date of sale owned more than a 5% interest in the trust; or
- the trust units cease to be regularly traded on an established securities
exchange.

Gain realized by a foreign holder upon the sale by the trust of all or any
part of the net profits interests would be subject to federal income tax.

Trust unitholders who are foreign holders may elect under Internal Revenue
Code Section 871 or Section 882 or similar provisions of applicable treaties to
treat income attributable to the net profits interests as effectively connected
with the conduct of a trade or business in the United States. The foreign holder
will then be taxed at regular federal income tax rates on the net income rather
than gross income attributable to the net profits interests, including gain
recognized on the disposition of trust units. Absent a treaty exception, the net
income of a corporate foreign holder which has made an election will also be
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subject to the branch profits tax imposed under Section 884 to the extent such
net income is not reinvested in a United States trade or business. To claim the
deductions allowable in computing net income, including cost depletion, an
electing foreign holder must file a United States income tax return. To avoid
tax withholding, an electing foreign holder must provide proper certificates or
other evidence to the withholding agent. Once made, the election is irrevocable
unless an applicable treaty allows the election to be made annually. The
election is applicable to all income and gain realized by the foreign holder on
any real property interests located in the United States, including those
interests held through partnerships, fixed investment trusts, and other
pass-through entities.

BACKUP WITHHOLDING

In general, distributions of trust income will not be subject to backup
withholding unless the trust unitholder is an individual or other noncorporate
taxpayer and he fails to furnish his taxpayer identification number to the
trustee in the manner required or he otherwise fails to comply with certain
reporting procedures.

TAX SHELTER REGISTRATION

Eastern States believes that the requirements for tax shelter registration
under Internal Revenue Code Section 6111 would be met if any trust unitholder's
investment base is substantially reduced by borrowing. To avoid any potential
penalty, the trust will be registered as a tax shelter with the IRS. The trustee
will furnish the tax shelter registration number to each trust unitholder. Each
trust unitholder must disclose this number by attaching Form 8271 to his tax
return.

ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THIS
INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED
BY THE IRS.

REPORTS

The trustee will furnish to trust unitholders of record quarterly and
annual reports to facilitate their computation of their tax liability. For a
further discussion of the trustee's reporting obligations, see "Description of
the Trust Units -- Periodic Reports."

STATE TAX CONSIDERATIONS

This section is a brief summary of the material state income tax and other
state tax considerations affecting the trust and the trust unitholders. No
attempt has been made in the following discussion to comment on all state tax
matters affecting the trust or trust unitholders. This discussion focuses on
trust unitholders who are individuals not residing in either Kentucky or West
Virginia, as applicable, and has only limited application to corporations,
estates, trusts or other trust unitholders subject to specialized tax treatment,
such as tax-exempt institutions, IRAs, REITs or mutual funds. Accordingly, each
prospective trust unitholder should consult, and should depend on, his own tax
advisor in analyzing the particular state and local tax consequences to him of
an investment in the trust.

The trust will not request rulings from the West Virginia or Kentucky state
tax authorities dealing with the state tax consequences of ownership of trust
units. Instead, the trust will rely on the opinion of Goodwin & Goodwin
regarding the West Virginia state tax consequences described below and on the
opinion of Vorys, Sater, Seymour and Pease LLP regarding the Kentucky state tax
consequences described below.

Goodwin & Goodwin, LLP believes that its opinion is in accordance with the
position of the West Virginia state tax authorities regarding grantor trusts.
This opinion is not binding on the West Virginia state tax authorities or the
courts and we cannot assure you that the West Virginia state tax authorities or
the courts will agree with it.

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Vorys, Sater, Seymour and Pease LLP believes that its opinion is in
accordance with the position of the Kentucky state tax authorities regarding
grantor trusts. This opinion is not binding on the Kentucky state tax
authorities or the courts and we cannot assure you that the Kentucky state tax
authorities or the courts will agree with it.

INCOME TAX CONSIDERATIONS

The trust will own net profits interests burdening oil and gas properties
located in the states of Kentucky and West Virginia. These states impose income
taxes on residents and, for income from sources within these states, including
income from properties located in these states, nonresidents. A trust 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 these
requirements. Trust unitholders may also be subject to taxation by their state
of residence on income derived from the trust.

The income tax laws of Kentucky and West Virginia are based on federal
income tax laws. Assuming the trust is taxed as a grantor trust for federal
income tax purposes, the trust will not be subject to Kentucky or West Virginia
state income taxation but the trust unitholders will be subject to income tax in
both of these states on their share of income from the net profits interests
burdening properties located in that state. The trustee will provide information
concerning the trust sufficient to identify the income of the trust allocable to
each state. Individual nonresident trust unitholders with West Virginia adjusted
gross income from West Virginia sources in excess of the sum of West Virginia
personal exemptions are required to file a West Virginia state income tax
return. Individuals are currently allowed a West Virginia personal exemption of
$2,000 for each exemption allowed for federal income tax purposes. Individual
nonresident trust unitholders with gross income from Kentucky sources and $5,000
of total gross income must file a Kentucky state income tax return. It is
uncertain whether trust unitholders who are nonresidents of Kentucky or West
Virginia will be taxed in these states on gains from sales of trust units.

West Virginia imposes a withholding tax on distributions made to
nonresident individuals by an entity that is treated as a conduit of its income
for tax purposes. The trust does not believe it is an entity that is required to
withhold West Virginia taxes from distributions to trust unitholders who are not
West Virginia residents and does not intend to do so unless counsel advises that
such withholding is required. The trust would, if required, withhold 4% of the
taxable income of each nonresident trust unitholder attributable to West
Virginia sources. Distributions to trust unitholders are not currently subject
to Kentucky withholding tax. If Kentucky enacts a nonresident withholding tax,
the trust may be required to withhold taxes from distributions made to
nonresident unitholders attributable to Kentucky source income. Taxes withheld
by the trust from a trust unitholder would be treated as a distribution to that
trust unitholder and allowed as a credit against that trust unitholder's state
tax liability.

PROBATE AND PROPERTY CONSIDERATIONS

The trust units may constitute real property or an interest in real
property under the inheritance, estate and probate laws of Kentucky or West
Virginia. If the trust 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 trust unitholders may be subject to devolution, probate and
administration laws, and inheritance or estate and similar taxes, under the laws
of that state.

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ERISA CONSIDERATIONS

The Employee Retirement Income Security Act of 1974 regulates pension,
profit-sharing and other employee benefit plans to which it applies. ERISA also
contains standards for persons who are fiduciaries of those plans. In addition,
the Internal Revenue Code provides similar requirements and standards which are
applicable to qualified plans, which include these types of plans and to
individual retirement accounts, whether or not subject to ERISA.

A fiduciary of a qualified plan should carefully consider fiduciary
standards under ERISA regarding the qualified plan's particular circumstances
before authorizing an investment in trust units. A fiduciary should consider

- whether the investment satisfies the prudence requirements of Section
404(a)(1)(B) of ERISA;
- whether the investment satisfies the diversification requirements of
Section 404(a)(1)(C) of ERISA; and
- whether the investment is in accordance with the documents and
instruments governing the qualified plan as required by Section
404(a)(1)(D) of ERISA.

A fiduciary should also consider whether an investment in trust units might
result in direct or indirect nonexempt prohibited transactions under Section 406
of ERISA and Internal Revenue Code Section 4975. In deciding whether an
investment involves a prohibited transaction, a fiduciary must determine whether
there are plan assets in the transaction. On November 13, 1986, the Department
of Labor published final regulations concerning whether or not a qualified
plan's assets would be deemed to include an interest in the underlying assets of
an entity for purposes of the reporting, disclosure and fiduciary responsibility
provisions of ERISA and analogous provisions of the Internal Revenue Code. These
regulations provide that the underlying assets of an entity will not be
considered "plan assets" if the equity interests in the entity are a publicly
offered security. Eastern States expects that at the time of the sale of the
trust units in this offering, they will be publicly offered securities.
Fiduciaries, however, will need to determine whether the acquisition of trust
units is a nonexempt prohibited transaction under the general requirements of
ERISA Section 406 and Internal Revenue Code Section 4975.

The prohibited transaction rules are complex, and persons involved in
prohibited transactions are subject to penalties. For that reason, potential
qualified plan investors should consult with their counsel to determine the
consequences under ERISA and the Internal Revenue Code of their acquisition and
ownership of trust units.

DESCRIPTION OF THE TRUST AGREEMENT

The following information and the information included under "Description
of the Trust Units" summarize the material information contained in the trust
agreement. This summary may not contain all the information that is important to
you. For more detailed provisions concerning the trust, you should read the
trust agreement. A copy of the trust agreement is filed as an exhibit to the
registration statement. See "Available Information."

CREATION AND ORGANIZATION OF THE TRUST; AMENDMENTS

Eastern States will create the net profits interests and transfer them to
the trust in exchange for
trust units. The transfers of the net profits interests will be effective as of
September 1, 1999.

Eastern States organized the trust under the Delaware Business Trust Act to
acquire and hold the net profits interests for the benefit of the trust
unitholders under a trust agreement among Eastern States, the property trustee
and the Delaware trustee. Neither the trust nor the property trustee has any
control over or responsibility for costs relating to the operation of the
underlying properties. Eastern States has no contractual commitments to the
trust to conduct further drilling on or to maintain its ownership interest in
any of these properties. For a description of the underlying properties and
other information relating to them, see "The Underlying Properties."

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The beneficial interest in the trust is divided into 10,500,000 trust
units. Each of the trust units represents an equal undivided beneficial interest
in the assets of the trust. You will find additional information concerning the
trust units in "Description of the Trust Units."

Amendment of the trust agreement requires a vote of holders of 66 2/3% or
more of the outstanding trust units. However, no amendment may:
- increase the power of the property trustee to engage in business or
investment activities;
- alter the rights of the trust unitholders as among themselves; or
- permit the property trustee to distribute the net profits interests in
kind.

Provided that they do not adversely affect the interests of the trust
unitholders, the following amendments do not require the vote of trust
unitholders:

- correcting any ambiguities;

- correcting defects and inconsistencies; and

- changing the name of the trust.

ASSETS OF THE TRUST

The assets of the trust consist of net profits interests and any cash and
temporary investments being held for the payment of expenses and liabilities or
for distribution to the trust unitholders.

DUTIES AND LIMITED POWERS OF THE PROPERTY TRUSTEE

The duties of the property trustee are specified in the trust agreement and
by the laws of the State of Delaware. The property trustee's principal duties
consist of:

- collecting cash attributable to the net profits interests;
- paying expenses, charges and obligations of the trust from the trust's
cash and assets;

- distributing distributable cash to the trust unitholders;

- furnishing trust unitholders with information necessary for federal and
state tax purposes; and

- taking any action it deems necessary and advisable to best achieve the
purposes of the trust.

If a trust liability is contingent or uncertain in amount or not yet
currently due and payable, the property trustee may create a cash reserve to pay
for the liability. If the property trustee determines that the cash on hand and
the cash to be received is insufficient to cover the trust's liability, the
property trustee may borrow funds required to pay the liabilities. The property
trustee may borrow the funds from any person, including itself. The property
trustee may also mortgage the assets of the trust to secure payment of the
indebtedness. If the property trustee borrows funds, the trust unitholders will
not receive distributions until the borrowed funds are repaid.

Each quarter, the property trustee will pay trust obligations and expenses
and distribute to the trust unitholders the remaining cash received from the net
profits interests. The cash held by the property trustee as a reserve against
future liabilities or for distribution at the next distribution date must be
invested in:

- interest bearing obligations of the United States government;
- repurchase agreements secured by interest-bearing obligations of the
United States government;
- money market mutual funds; or
- bank certificates of deposit.

The trust may not acquire any asset except the net profits interests, cash
and temporary cash investments, and it may not engage in any investment activity
except investing cash on hand.

At the request of Eastern States, the property trustee must sell for cash
the net profits interests relating to the underlying properties sold by Eastern
States to an unaffiliated third party. However, these sales are required only if
the net profits interests sold do not exceed $3 million in any calendar year or

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$20 million on an aggregate basis for the life of the trust. Upon such a sale,
Eastern States will, or will cause the purchaser to, pay to the trust the
portion of the purchase price allocable to the net profits interests sold, less
allocable expenses of the sale, including attorneys' fees.

The property trustee may sell the net profits interests in any of the
following circumstances:

- the sale does not involve trust assets of which the aggregate
standardized measure exceeds $30 million and is in the best interests of
the trust unitholders and a majority of the trust units represented at a
meeting of the trust unitholders where a quorum is present approve the
sale; or

- the sale involves trust assets of which the aggregate standardized
measure exceeds $30 million and is in the best interests of the trust
unitholders and holders representing at least 66 2/3% of the outstanding
trust units approve the sale.

Upon dissolution of the trust the property trustee must sell the net
profits interests. No trust unitholder approval is required in this event. The
trustee will distribute the net proceeds from any sale of the net profits
interests to the trust unitholders after payment of all liabilities of the trust
in accordance with law.

The property trustee may require any trust unitholder to dispose of his
trust units if an administrative or judicial proceeding seeks to cancel or
forfeit any of the property in which the trust holds an interest because of the
nationality or any other status of that trust unitholder. If a trust unitholder
fails to dispose of his trust units, the property trustee has the right to
purchase them and to borrow funds to make that purchase.

The property trustee may agree to modifications of the terms of the
conveyances or to settle disputes involving the conveyances. The property
trustee may not agree to modifications or settle disputes involving the royalty
part of the conveyances if these actions would change the character of the net
profits interests in a way that the net profits interests become working
interests or that the trust becomes an operating business.

DUTIES AND LIMITED POWERS OF THE DELAWARE TRUSTEE

The duties of the Delaware trustee are specified in the trust agreement and
by the laws of the State of Delaware. The Delaware trustee's principal duties
are to execute, deliver, acknowledge and file all necessary documents and to
maintain all necessary records of the trust as required by the laws of the State
of Delaware.

Unless specifically authorized in writing by the property trustee and
consented to by the Delaware trustee, the Delaware trustee shall not participate
in any decisions or possess any authority regarding the administration of the
trust, the investment of the trust's property or distributions to trust
unitholders.

LIABILITIES OF THE TRUST

Because the trust does not conduct an active business and the property
trustee has minimal power to incur obligations, Eastern States expects that the
trust will only incur liabilities for routine administrative expenses. These
might include the trustee's fees and accounting, engineering, legal and other
professional fees.

RESPONSIBILITY AND LIABILITY OF THE PROPERTY TRUSTEE

Under the trust agreement, the property trustee is required to act in the
best interests of the trust unitholders at all times. The property trustee must
exercise the same judgment and care in supervising and managing the trust's
assets as persons of ordinary prudence, discretion and intelligence would
exercise.

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The property trustee will not make business decisions affecting the assets
of the trust. Therefore, substantially all of the property trustee's functions
under the trust agreement are expected to be ministerial in nature. The trust
agreement, however, provides that the trustee may:

- charge a fee for its services as trustee;
- retain funds to pay for future expenses and deposit them in its own
account;
- lend funds at commercial rates to the trust to pay the trust's expenses;
and
- reimburse itself from the trust for its out-of-pocket expenses.

For a description of the functions of the property trustee, see "-- Duties and
Limited Powers of the Property Trustee" above.

In discharging its duty to trust unitholders, the property trustee may act
in its discretion and will be liable to the trust unitholders only for fraud,
gross negligence or acts or omissions constituting bad faith. The property
trustee will not be liable for any act or omission of its agents or employees
unless the property trustee acted in bad faith or with gross negligence in their
selection and retention. The property trustee will be indemnified individually
or as property trustee for any liability or cost that it incurs in the
administration of the trust, except in cases of fraud, gross negligence or bad
faith. The property trustee will have a lien on the assets of the trust as
security for this indemnification and its compensation earned as property
trustee. The property trustee is entitled to indemnification from trust assets
or, to the extent that trust assets are insufficient, from Eastern States. Trust
unitholders will not be liable to the property trustee for any indemnification.
The property trustee may not cause the trust to incur any contractual
liabilities that are not limited to the assets of the trust and will be liable
for its failure to do so. For a description of the limitations on the liability
of trust unitholders, see "Description of the Trust Units -- Liability of Trust
Unitholders."

Delaware law permits the trust unitholders to file actions seeking other
remedies, including:

- removal of the trustees;

- specific performance;

- appointment of a receiver;

- an accounting by the property trustee to trust unitholders; and

- punitive damages.

CONDITIONAL RIGHT OF REPURCHASE

The trust agreement provides that Eastern States and any of its successors,
affiliates and transferees will retain the right to repurchase all, but not less
than all, outstanding trust units at any time during which 15% or less of the
outstanding trust units are owned by persons or entities other than Eastern
States and its affiliates. Subject to the following sentence, any such
repurchase would be at a price equal to the greater of

(1) the highest price at which Eastern States or any of its affiliates
acquired trust units during the 90 days immediately preceding the
determination date; and

(2) the average closing price of trust units on the NYSE for the 30
trading days immediately preceding the determination date.

If Eastern States or any of its affiliates acquires trust units, excluding an
acquisition from Eastern States or any affiliate, during the period that is
three trading days after the determination date at a price per trust unit
greater than that at which an acquisition was made during the 90-day period
referred to in clause (1) of the preceding sentence, then for purposes of clause
(1) of the preceding sentence the highest price used therein shall be such
greater price. The determination date is three trading days prior to the date
that notice of the exercise is delivered to trust unitholders. Any repurchase
would be conducted in accordance with applicable Federal and state securities
laws, including, without limitation, Rule 13e-4 of the Securities Exchange Act
of 1934 to the extent then applicable.

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If Eastern States elects to purchase all the trust units, Eastern States
and the property trustee will, prior to the date fixed for purchase, give all
unitholders of record not less than 15 days' nor more than 60 days' written
notice. The notice will specify the time and place of the repurchase, calling
upon each trust unitholder to surrender to Eastern States or its agent on the
repurchase date at the place designated in the notice its certificate or
certificates representing the number of trust units specified in the notices. On
or after the repurchase date, each holder of trust units must present and
surrender to Eastern States or its agent its certificates for its trust units at
the place designated and thereupon the purchase price of the trust units shall
be paid to or on the order of the person or entity whose name appears on the
certificate or certificates as the owner thereof. In no event may fewer than all
of the outstanding trust units represented by the certificates be repurchased,
excluding any units held by Eastern States and any of its affiliates.

If Eastern States and the property trustee give a notice of repurchase and
if, on or before the date fixed for repurchase, the funds necessary for the
repurchase shall have been set aside by Eastern States, separate and apart from
its other funds, in trust for the pro rata benefit of the holders of the trust
units then, notwithstanding that any certificate for the trust units has not
been surrendered, at the close of business on the repurchase date the holders of
units shall cease to be unitholders and shall have no interest in or claims
against Eastern States, the trust, the Delaware trustee or the property trustee
by virtue thereof and shall have no voting or other rights with respect to the
trust units, except the right to receive the purchase price payable upon
repurchase, without interest thereon and without any other distributions for
record dates after the date of notice of the repurchase, upon surrender and
endorsement, if required by Eastern States of their certificates. The trust
units evidenced thereby will no longer be held of record in the names of the
unitholders. Subject to applicable escheat laws, any monies so set aside by
Eastern States and unclaimed at the end of two years from the repurchase date
will revert to the general funds of Eastern States, after which reversion the
holders of units so noticed for repurchase may look only to the general funds of
Eastern States for the payment of the purchase price. Any interest accrued on
funds so deposited would be paid to Eastern States from time to time as
requested by Eastern States.

If Eastern States exercises and consummates its right of repurchase, then
at its option it may cause the trust to be terminated by providing written
notice thereof to the property trustee and the Delaware trustee. Within 30 days
following written notice of Eastern States' decision to terminate the trust, the
property trustee and the Delaware trustee must cause all net profits interests
and, subject to the rights of unitholders with respect to the receipt of
distributions for which a record date has been determined, all proceeds of
production attributable to the net profits interests and any other assets of the
trust to be transferred to Eastern States or its assignee, subject to the right
of the property trustee and Delaware trustee to create reasonable reserves in
connection with the liquidation of the trust.

DURATION OF THE TRUST; SALE OF NET PROFITS INTERESTS

The trust will dissolve if:

- the trust sells all of the net profits interests;

- annual net proceeds for West Virginia are less than $3.5 million for each
of two consecutive years after the year 2000;

- annual net proceeds for Kentucky are less than $3.5 million for each of
two consecutive years after the year 2000;

- the holders of 66 2/3% or more of the outstanding trust units vote in
favor of termination;
- Eastern States exercises its conditional right of repurchase; or
- a judicial dissolution of the trust occurs.

The property trustee would then sell all of the trust's assets, either by
private sale or public auction, and, after payment of liabilities of the trust,
distribute the net proceeds of the sale to the trust unitholders. Thereafter the
trust will terminate.

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DISPUTE RESOLUTION

Any dispute, controversy or claim that may arise between Eastern States and
the property trustee relating to the trust will be submitted to binding
arbitration before a tribunal of three arbitrators. The tribunal of three
arbitrators shall be selected as follows: one arbitrator selected by the
claimant; one arbitrator selected by the respondent; and one arbitrator mutually
selected by the other two arbitrators.

COMPENSATION OF THE PROPERTY TRUSTEE AND THE DELAWARE TRUSTEE

The property trustee's and the Delaware trustee's compensation will be paid
out of the trust's assets. For a further discussion of the trustee's
compensation, see "The Trust."

MISCELLANEOUS

The property trustee may consult with counsel, accountants, geologists and
engineers and other parties the property trustee believes to be qualified as
experts on the matters for which advice is sought. The property trustee will be
protected for any action it takes in good faith reliance upon the opinion of an
expert.

DESCRIPTION OF THE TRUST UNITS

Each trust unit is a unit of beneficial ownership in the trust and
represents an undivided beneficial interest in the assets of the trust. Each
trust unitholder has the same rights regarding each of his trust units as every
other trust unitholder has regarding his units. The trust will have 10,500,000
trust units outstanding upon completion of the offering.

DISTRIBUTIONS AND INCOME COMPUTATIONS

Each quarter, the property trustee will determine the amount of funds
available for distribution to the trust unitholders. Available funds are the
excess cash received by the trust from the net profits interests and other
sources that quarter, over the trust's liabilities for that quarter. Available
funds will be reduced by any cash the property trustee decides to hold as a
reserve against future liabilities. Trust unitholders that own their trust units
on the record date, which is the 15th day of the third calendar month after the
end of the respective quarter, will receive a quarterly distribution no later
than the 25th day of the third month after the end of the respective quarter.
The first distribution will be made on or before December 25, 1999 to trust
unitholders owning trust units on December 15, 1999 for the production period
September 1, 1999 through September 30, 1999. The second distribution will be
made on or before March 25, 2000 to trust unitholders owning trust units on
March 15, 1999 for the production period October 1, 1999 through December 31,
1999.

Unless otherwise advised by counsel, the property trustee will treat the
income and expenses of the trust for each quarter as belonging to the trust
unitholders of record on the record date for that quarter. For a further
description of the income tax treatment of unit ownership, see "Federal Income
Tax Consequences" and "State Tax Considerations."

TRANSFER OF TRUST UNITS

Trust unitholders may transfer their trust units by sending their trust
unit certificate to the property trustee along with a transfer form that is
properly completed. The property trustee will not require either the transferor
or transferee to pay a service charge for any transfer of a trust unit. The
property trustee may require payment of any tax or other governmental charge
imposed for a transfer. The property trustee may treat the registered owner of
any trust unit as shown by its records as the owner of the trust unit. The
property trustee will not be considered to know about any claim or demand on a
trust unit by any party except the record owner. A person who acquires a trust
unit after any record date will not be entitled to the distribution relating to
that record date. Delaware law will govern all matters affecting the title,
ownership, warranty or transfer of trust units.
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PERIODIC REPORTS

No later than 120 days following the end of each year, the property trustee
will mail to the trust unitholders an annual report containing audited financial
statements of the trust.

The property trustee will file all required trust federal and state income
tax and information returns. The property trustee will prepare and mail to trust
unitholders annually reports that trust unitholders need to report their share
of the income and deductions of the trust.

Each trust unitholder and his representatives may examine, for any proper
purpose and during reasonable business hours, the records of the trust and the
property trustee.

LIABILITY OF TRUST UNITHOLDERS

Under the Delaware Business Trust Act, trust unitholders will be entitled
to the same limitation of personal liability extended to stockholders of private
corporations for profit under the General Corporation Law of the State of
Delaware.

VOTING RIGHTS OF TRUST UNITHOLDERS

Trust unitholders have more limited voting rights than those of
stockholders of most public corporations. For example, there is no requirement
for annual meetings of trust unitholders or for annual or other periodic
re-elections of the property trustee.

The property trustee or trust unitholders owning at least 15% of the
outstanding trust units may call meetings of trust unitholders. Meetings must be
held in Fort Worth, Texas. The property trustee must send written notice of the
time and place of the meeting and the matters to be acted upon to all of the
trust unitholders at least 20 days and not more than 60 days before the meeting.
Trust unitholders representing a majority of trust units outstanding must be
present or represented to have a quorum. Each trust unitholder is entitled to
one vote for each trust unit owned.

Under the trust agreement, a matter is approved by the vote of a majority
of the trust units held by the trust unitholders at a meeting where there is a
quorum. This is true, even if a majority of the total trust units did not
approve it. The affirmative vote of the holders of 66 2/3% of the outstanding
trust units is required to:

- dissolve the trust;
- amend the trust agreement for matters that adversely affect the right of
trust unitholders in a material respect; or
- approve the sale of all or any material part of the assets of the trust.

The property trustee must consent before all or any part of the trust
assets can be sold except in connection with the termination of the trust or
limited sales directed by Eastern States in conjunction with its sale of
underlying properties. The property trustee may be removed, with or without
cause, by the vote of the holders of a majority of the outstanding trust units.

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COMPARISON OF TRUST UNITS AND COMMON STOCK

You should be aware of the following ways in which an investment in trust
units is different from an investment in common stock of a corporation.

TRUST UNITS COMMON STOCK
----------- ------------

Voting Limited voting rights. Corporate statutes provide
specific voting rights to
stockholders on electing
directors and major corporate
transactions.
Income Tax The trust is not subject to Corporations are taxed on
tax; trust unitholders are their income, and their
directly subject to income stockholders are taxed on
tax on their proportionate dividends received.
share of trust net income,
adjusted for tax deductions.
Distributions Substantially all trust cash Stockholders receive
receipts are distributed to dividends at the discretion
trust unitholders. of the board of directors.
Business and Assets Interest is limited to A corporation conducts an
specific assets with a finite active business for an
economic life. unlimited term and can
reinvest its earnings and
raise additional capital to
expand.
Fiduciary Duties To the extent provided in the Officers and directors have a
trust agreement, the property fiduciary duty of loyalty to
trustee has a fiduciary duty stockholders and a duty to
to the trust unitholders. use due care in management
Eastern States does not owe and administration of a
the trust unitholders a corporation.
fiduciary duty.

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UNDERWRITING

Under the terms and subject to the conditions contained in the underwriting
agreement, the form of which is filed as an exhibit to the registration
statement, the underwriters named below, for whom Lehman Brothers Inc., Salomon
Smith Barney Inc., PaineWebber Incorporated, CIBC World Markets Corp., Credit
Suisse First Boston Corporation, Dain Rauscher Wessels, a division of Dain
Rauscher Incorporated, Donaldson, Lufkin & Jenrette Securities Corporation, A.G.
Edwards & Sons, Inc., and McDonald Investments Inc. are acting as
representatives, have agreed to purchase from Eastern States, and Eastern States
has agreed to sell to each underwriter, the number of trust units set forth
opposite the name of such underwriter below:

NUMBER OF
TRUST UNITS
UNDERWRITERS -----------

Lehman Brothers Inc. .......................................
Salomon Smith Barney Inc. ..................................
PaineWebber Incorporated....................................
CIBC World Markets Corp. ...................................
Credit Suisse First Boston Corporation......................
Dain Rauscher Wessels.......................................
Donaldson, Lufkin & Jenrette Securities Corporation.........
A.G. Edwards & Sons, Inc. ..................................
McDonald Investments Inc. ..................................
---------
Total............................................. 7,875,000
=========

Eastern States has granted to the underwriters an option to purchase up to
an additional 1,181,250 trust units, exercisable solely to cover
over-allotments, at the initial public offering price, less the underwriting
discounts and commissions shown on the cover page of this prospectus. Such
option may be exercised at any time until 30 days after the date of the
underwriting agreement. To the extent that the option is exercised, each
underwriter will be committed, subject to conditions specified in the
underwriting agreement, to purchase a number of the additional trust units that
is proportionate to such underwriter's initial commitment as indicated on the
preceding table.

The following table shows the per trust unit and total underwriting
discounts and commissions to be paid to the underwriters by Eastern States.
These amounts are shown assuming both no exercise and full exercise of the
underwriters' option to purchase 1,181,250 additional units.

PAID BY EASTERN STATES
---------------------------
NO EXERCISE FULL EXERCISE
----------- -------------

Per trust unit..............................................
Total.......................................................

The underwriters propose to offer the trust units to the public at the
initial public offering price set forth on the cover page of this prospectus and
to certain dealers at such initial public offering price less a selling
concession not in excess of $ per trust unit. The underwriters may allow,
and such dealers may reallow, a concession not in excess of $ per trust unit
to certain other underwriters or to certain other brokers or dealers. After the
initial offering of the trust units to the public, the offering price and other
selling terms may from time to time be changed by the representatives.

The underwriting agreement provides that the obligations of the
underwriters to pay for and accept delivery of the trust units offered hereby
are subject to approval of certain legal matters by counsel and to other
specified conditions, including the condition that no stop order suspending the
effectiveness of the registration statement is in effect and no proceedings for
such purpose are pending or threatened by the SEC, and that there has been no
material adverse change or development involving a prospective material adverse
change in the condition of the trust or the underlying properties from that set
forth in the

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registration statement otherwise than as set forth or contemplated in this
prospectus, and that certificates, opinions and letters specified in the
underwriting agreement have been received from Eastern States and its counsel.
The underwriters are obligated to take and pay for all trust units (other than
those covered by the underwriters' over-allotment option described below) if any
such trust units are taken.

Eastern States and the trust have agreed in the underwriting agreement to
indemnify the underwriters against civil liabilities to the extent specified in
that agreement, including liabilities under the Securities Act, and to
contribute to payments that the underwriters may be required to make for such
liabilities. The trust's indemnity obligations are limited to the assets of the
trust, and neither the trustee nor any unitholder will have any obligation to
indemnify the underwriters.

Eastern States has agreed that they will not, without the prior written
consent of Lehman Brothers Inc., during the 180 days following the date of this
prospectus, (1) offer for sale, sell, pledge or otherwise dispose of (or enter
into any transaction or device which is designed to, or could be expected to,
result in the disposition by any person at any time in the future of) any trust
units or any securities that are convertible into, or exercisable or
exchangeable for, or that represent the right to receive, trust units, or (2)
enter into any swap or other derivatives transaction that transfers to another,
in whole or in part, any of the economic benefits or rights of ownership of such
trust units.

The underwriters have advised Eastern States that they do not intend to
confirm any sales to accounts over which they exercise discretionary authority.

Until the distribution of the trust units is completed, the rules of the
SEC may limit the ability of the underwriters and certain selling group members
to bid for and purchase trust units. As an exception to these rules, the
representatives are permitted to engage in certain transactions that stabilize
the price of the trust units. Such transactions may consist of bids or purchases
for the purpose of pegging, fixing or maintaining the price of the trust units.

In addition, if the representatives over-allot, that is, if they sell more
trust units than are set forth on the cover page of this prospectus, and thereby
create a short position in the trust units in connection with the offering, the
representatives may reduce that short position by purchasing trust units in the
open market. The representatives may also elect to reduce any short position by
exercising all or part of the over-allotment option described herein.

In addition, if the underwriters purchase trust units in the open market
for the account of the underwriting syndicate and the trust units purchased can
be traced to a particular underwriter or selling group member, the underwriting
syndicate may impose a "penalty bid" on the selling underwriter or member for
reselling trust units back to the syndicate. The penalty bid can be a
requirement that the underwriter purchase the trust units it sold at the cost
price to the syndicate or a requirement that the underwriter or selling group
member repay to the syndicate account the selling concession it earned at the
sale of the trust units. As a result, an underwriter or selling group member
and, in turn brokers, may lose the fees that they otherwise would have earned
from a sale of the trust units if their customer resells the trust units while
the penalty bid is in effect. The imposition of a penalty bid might have an
effect on the price of the trust units if it discouraged resales of trust units
by purchasers in the offering.

In general, purchases of a security for the purpose of stabilization or to
reduce a syndicate short position could cause the price of the security to be
higher than it might otherwise be in the absence of such purchases. The
imposition of a penalty bid might have an effect on the price of a security to
the extent that it were to discourage resales of the security by purchasers in
the offering.

Neither Eastern States, the trust nor any of the underwriters makes any
representation or prediction as to the direction or magnitude of any effect that
the transactions described above may have on the price of the trust units. In
addition, neither Eastern States, the trust nor any of the underwriters makes
any representation that the representatives will engage in such transactions or
that such transactions, once commenced, will not be discontinued without notice.

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Prior to the offering, there has been no public market for the trust units.
The initial public offering price was negotiated between Eastern States and the
representatives. The factors considered in determining the initial public
offering price of the trust units include prevailing market conditions,
estimates of distributions to trust unitholders and the overall quality of the
underlying properties. The initial public offering price set forth on the cover
page of this prospectus should not, however, be considered an indication of the
actual value of the trust units. Such price will be subject to change as a
result of market conditions and other factors. There can be no assurance that an
active trading market will develop for the trust units or that the trust units
will trade in the public market subsequent to the offering at or above the
initial public offering price.

Eastern States estimates that the total expenses of the offering, other
than underwriting discounts and commissions, will be approximately $1.5 million.

The trust has applied to have the trust units listed on the NYSE under the
symbol "ANG."

A prospectus may be made available in electronic format on an Internet
website maintained by Fidelity Investments, which is expected to act as one of
the dealers in the offering.

Because it is expected that the National Association of Securities Dealers,
Inc. will view the trust units offered hereby as interests in a direct
participation program, the offering is being made in compliance with Rule 2810
of the NASD's Conduct Rules.

SELLING TRUST UNITHOLDER

Eastern States currently owns all of the 10,500,000 outstanding trust
units. It is offering 7,875,000 trust units in this offering, or 9,056,250 trust
units if the underwriters exercise their over-allotment option in full.

Eastern States may sell trust units, exchange them for oil and natural gas
properties or use them for other corporate purposes.

Prior to this offering there has been no public market for the trust units.
Eastern States cannot predict the effect on future market prices, if any, of
market sales of trust units or the availability of trust units for sale if it
disposes of its trust units. Nevertheless, sales of substantial amounts of trust
units in the public market could adversely affect prevailing market prices.

VALIDITY OF THE TRUST UNITS

Counsel for Eastern States and the trust, Andrews & Kurth L.L.P., Houston,
Texas will give the tax opinion described in the section of this prospectus
captioned "Federal Income Tax Consequences" and other matters. Richards, Layton
& Finger, P.A. will give a legal opinion as to the validity of the trust units.
Certain legal matters in connection with the trust units offered hereby will be
passed upon for the underwriters by Baker & Botts, L.L.P., Houston, Texas.

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EXPERTS

Information appearing in this prospectus regarding the August 31, 1999
estimated quantities of reserves of the underlying properties and net profits
interests owned by the trust, the future net revenues from those reserves and
their present value was prepared by Ryder Scott Company, L.P., independent
petroleum engineers.

Ernst & Young LLP, independent auditors, have audited the Statements of
Revenues and Direct Operating Expenses of the Underlying Properties of Eastern
States Oil and Gas, Inc. for each of the three years in the period ended
December 31, 1998, the Statement of Assets and Trust Corpus of Appalachian
Natural Gas Trust, formerly the Appalachian Basin Royalty Trust, as of August
19, 1999, the Consolidated Financial Statements of Eastern States Oil and Gas,
Inc. as of December 31, 1998 and 1997, and for each of the three years in the
period ended December 31, 1998, and the Consolidated Financial Statements of the
domestic operations of Blazer Energy Corp. for the year ended September 30,
1996, as set forth in their reports. We have included these financial statements
in the prospectus and elsewhere in the registration statement in reliance on
Ernst & Young LLP's reports, given on their authority as experts in accounting
and auditing.

AVAILABLE INFORMATION

The trust and Eastern States have filed with the SEC in Washington, D.C. a
registration statement, including all amendments, under the Securities Act of
1933 relating to the trust units. As permitted by the rules and regulations of
the SEC, this prospectus does not contain all of the information contained in
the registration statement and the exhibits and schedules to the registration
statement. You may read and copy the registration statement or other information
at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C.
20549. You may request copies of these documents, upon payment of a duplicating
fee, by writing to the SEC at the address in the previous sentence. To obtain
information on the operation of the public reference rooms you may call the SEC
at (800) SEC-0330. Eastern States' filings will also be available to the public
on the SEC Internet Web site at http://www.sec.gov.

Bank One, Texas, N.A. is the property trustee of the trust. The property
trustee's address is 500 Throckmorton, Suite 801, Fort Worth, Texas 76102,
Attention: Corporate Trust Department.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

In this prospectus the following terms have the meanings specified below.

Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of crude oil
or other liquid hydrocarbons.

Bcf -- One billion cubic feet of natural gas.

Bcfe -- One billion cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.

Btu -- A British Thermal Unit, a common unit of energy measurement.

Estimated Future Net Cash Flow -- The result of applying current prices of
oil and natural gas to estimated future production from oil and natural gas
proved reserves, reduced by estimated future expenditures, based on current
costs to be incurred, in developing and producing the proved reserves, excluding
overhead.

MBbl -- One thousand Bbl.

Mcf -- One thousand cubic feet of natural gas.

Mcfe -- One thousand cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.

MMbtu -- One million Btus.

MMcf -- One million cubic feet of natural gas.

MMcfe -- One million cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.

Natural Gas Revenue -- Includes revenue related to the sale of natural gas,
natural gas liquids and plant products.

Net Wells or Acres -- Determined by multiplying "gross" wells or acres by
the interest in such wells or acres represented by the underlying properties.

Net Profits Interest (also called a net overriding royalty interest) -- A
nonoperating interest that creates a share in gross production from an operating
or working interest in oil and gas properties. The share is measured by net
profits from the sale of production after deducting production and property
taxes, development and production costs and overhead.

NYMEX -- New York Mercantile Exchange, where futures and options contracts
for the oil and natural gas industry and some precious metals are traded.

Overriding Royalty Interest -- A royalty interest created or "carved" out
of a working or operating interest. Its term extends for the same term as the
working interest from which it is carved.

Proved Developed Reserves -- Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.

Proved Reserves -- The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering data,
appear with reasonable certainty to be recoverable in the future from known oil
and natural gas reservoirs under existing economic and operating conditions.

The Securities and Exchange Commission definition of proved oil and gas
reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows:

Proved oil and gas reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating

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conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.

(1) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.

(2) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when 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.

(3) Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (B) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (C) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and (D) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.

Proved Undeveloped Reserves -- Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required.

Reserve-to-Production Index -- An estimate, expressed in years, of the
total estimated proved reserves attributable to a producing property divided by
production from the property for the 12 months preceding the date as of which
the proved reserves were estimated.

Royalty Interest -- A real property interest entitling the owner to receive
a specified portion of the gross proceeds of the sale of oil and natural gas
production or, if the transfer document or conveyance creating the interest
provides, a specific portion of oil and natural gas produced, without any
deduction for the costs to explore for, develop or produce the oil and natural
gas. A royalty interest owner has no right to consent to or approve the
operation and development of the property, while the owners of the working
interest have the exclusive right to exploit the mineral on the land.

Standardized Measure of Discounted Future Net Cash Flows -- Also referred
to herein as "standardized measure." It is the present value of estimated future
net revenues computed by discounting estimated future net revenues at a rate of
10% annually. The Financial Accounting Standards Board requires disclosure of
standardized measure of discounted future net cash flows relating to proved oil
and gas reserve quantities, per paragraph 30 of Statement of Financial
Accounting Standards No. 69, as follows:

A standardized measure of discounted future net cash flows relating to an
enterprise's interests in (a) proved oil and gas reserves and (b) oil and gas
subject to purchase under long-term supply, purchase, or similar agreements and
contracts in which the enterprise participates in the operation of the
properties on which the oil or gas is located or otherwise serves as the
producer of those reserves shall be disclosed as of the end of the year. The
standardized measure of discounted future net cash flows relating to those two
types of interests in reserves may be combined for reporting purposes. The
following information shall be disclosed in the aggregate and for each
geographic area for which reserve quantities are disclosed:

a.Future cash inflows. These shall be computed by applying year-end prices
of oil and gas relating to the enterprise's proved reserves to the
year-end quantities of those reserves. Future price

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changes shall be considered only to the extent provided by contractual
arrangements in existence at year-end.

b.Future development and production costs. These costs shall be computed by
estimating the expenditures to be incurred in developing and producing
the proved oil and gas reserves at the end of the year, based on year-end
costs and assuming continuation of existing economic conditions. If
estimated development expenditures are significant, they shall be
presented separately from estimated production costs.

c.Future income tax expenses. These expenses shall be computed by applying
the appropriate year-end statutory tax rates, with consideration of
future tax rates already legislated, to the future pretax net cash flows
relating to the enterprise's proved oil and gas reserves, less the tax
basis of the properties involved. The future income tax expenses shall
give effect to tax deductions, tax credits and allowances relating to the
enterprise's proved oil and gas reserves.

d.Future net cash flows. These amounts are the result of subtracting future
development and production costs and future income tax expenses from
future cash inflows.

e.Discount. This amount shall be derived from using a discount rate of 10
percent a year to reflect the timing of the future net cash flows
relating to proved oil and gas reserves.

f.Standardized measure of discounted future net cash flows. This amount is
the future net cash flows less the computed discount.

Working Interest (also called an operating interest) -- A real property
interest entitling the owner to receive a specified percentage of the proceeds
of the sale of oil and natural gas production or a percentage of the production,
but requiring the owner of the working interest to bear the cost to explore for,
develop and produce such oil and natural gas. A working interest owner who owns
a portion of the working interest may participate either as operator or by
voting his percentage interest to approve or disapprove the appointment of an
operator and certain activities in connection with the development and operation
of a property.

74
79

INDEX TO FINANCIAL STATEMENTS

UNDERLYING PROPERTIES
Report of Independent Auditors............................ F-2
Statements of Revenues and Direct Operating Expenses for
the Years Ended December 31, 1996, 1997 and 1998 and
for the Eight Months Ended August 31, 1998, and 1999... F-3
Notes to Statements of Revenues and Direct Operating
Expenses............................................... F-4

APPALACHIAN NATURAL GAS TRUST
Report of Independent Auditors............................ F-8
Statement of Assets and Trust Corpus as of August 19,
1999................................................... F-9
Notes to Statement of Assets and Trust Corpus............. F-10
Pro Forma Statement of Assets and Trust Corpus
(Unaudited)............................................ F-11
Pro Forma Statement of Distributable Cash for the Year
Ended December 31, 1998 and for the Eight Months Ended
August 31, 1999 (Unaudited)............................ F-12
Notes to Pro Forma Statement of Distributable Cash
(Unaudited)............................................ F-13

F-1
80

REPORT OF INDEPENDENT AUDITORS

Board of Directors and Stockholder
Eastern States Oil & Gas, Inc.

We have audited the accompanying statements of revenues and direct
operating expenses of the Underlying Properties of Eastern States Oil & Gas,
Inc. for each of the three years in the period ended December 31, 1998. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the statements referred to above present fairly, in all
material respects, the revenues and direct operating expenses of the Underlying
Properties for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.

ERNST & YOUNG LLP

Vienna, Virginia

October 6, 1999, except for Note 5, as

to which the date is October 13, 1999

F-2
81

UNDERLYING PROPERTIES

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998

AND FOR THE EIGHT MONTHS ENDED AUGUST 31, 1998 AND 1999

(IN THOUSANDS)

EIGHT MONTHS
FOR THE YEARS ENDED, ENDED AUGUST 31,
--------------------------- -----------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
(UNAUDITED)

Revenues
Gas sales.................................. $54,877 $52,303 $41,835 $29,879 $25,594
Oil sales.................................. 677 531 242 157 230
------- ------- ------- ------- -------
Total.............................. 55,554 52,834 42,077 30,036 25,824
------- ------- ------- ------- -------
Direct Operating Expenses
Production and property taxes.............. 5,179 4,872 3,809 2,713 2,338
Production expenses........................ 6,300 5,106 3,603 2,401 2,401
------- ------- ------- ------- -------
Total.............................. 11,479 9,978 7,412 5,114 4,739
------- ------- ------- ------- -------
Excess of Revenues over Direct Operating
Expenses................................ $44,075 $42,856 $34,665 $24,922 $21,085
======= ======= ======= ======= =======

See accompanying Notes to Statements of Revenues and Direct Operating Expenses.

F-3
82

UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES

1. UNDERLYING PROPERTIES

The underlying properties (the "Underlying Properties") are predominantly
working interests in producing properties currently owned by Eastern States Oil
& Gas, Inc. (the "Company") in the Appalachian Basin in the states of West
Virginia and Kentucky. Effective September 1, 1999, the Company will convey an
80% net profits interests in 2,471 producing wells in Kentucky and West Virginia
and a 10% net profits interest in certain undeveloped properties in Kentucky and
West Virginia (together, the "Net Profits Interests") to the Appalachian Natural
Gas Trust (the "Trust"), formerly the Appalachian Basin Royalty Trust, excluding
certain specified interests. Estimated proved reserves attributable to the
Underlying Properties are approximately 1% oil and 99% natural gas, based on
discounted present value of estimated future net revenues as of August 31, 1999.
See Note 6.

All of the Underlying Properties were acquired by the Company from 1994
through 1998. Significant property acquisitions were made by the Company during
the three-year period presented in the accompanying financial statements. The
accompanying statements include the historical revenues and direct operating
expenses from these acquired properties for all years presented.

2. BASIS OF PRESENTATION

The statements of revenues and direct operating expenses of the Underlying
Properties were derived from the historical accounting records of the Company
(and prior owners for acquisitions occurring during the three-year period
presented), and are presented on the accrual basis of accounting before the
effects of conveyance of the Net Profits Interests. The point of sale for
revenue recognition is at the wellhead. Costs to transport and gather natural
gas have been deducted from the price paid at the wellhead. As a result,
production expenses exclude these costs. The statements do not include
depreciation, depletion and amortization, general and administrative or interest
expenses.

Royalty income of the Trust is determined based on an 80% net profits
interest percentage of net proceeds of the underlying wells and a 10% net
profits interest percentage of underlying leases. The computation of net profits
interest includes deductions for development costs. For the periods presented,
development costs (in thousands) were $12,024 in 1996 and $22,445 in 1997, none
in 1998 and none for the eight months ended August 31, 1999 since all wells
drilled in 1998 through August 31, 1999 have been excluded from the Underlying
Properties. In addition, the 1996 and 1997 development costs are only those
incurred by Eastern States and exclude development costs of Blazer Energy,
Corp., which owned a majority of the Underlying Properties prior to July 1,
1997, the effective acquisition date by Eastern States. Since the Company owns
greater than 97% working interest in the properties, it did not charge an
overhead fee to the properties in 1996 through 1998, but the trust will be
charged an overhead fee in the computation of trust income. Accordingly, royalty
income of the Trust will be materially different from the excess of revenues
over direct operating expenses from the Underlying Properties.

3. RELATED PARTY TRANSACTIONS

The Company sells approximately 68% of its natural gas production from the
Underlying Properties to the Company's affiliated marketing company, Statoil
Energy Services, Inc., generally at amounts approximating monthly market prices.

Sales from the Underlying Properties to the Company's marketing affiliate
Statoil Energy Services, Inc. were as follows (in thousands): $7,756, $27,227,
$27,966, $19,340, and $18,090 for the years 1996, 1997, 1998 and the eight
months ended August 31, 1998 and 1999, respectively.

F-4
83
UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES -- (CONTINUED)

4. CONTINGENCIES

The Company is involved in various legal actions and claims arising in the
normal course of business. Based upon its current assessment of the facts and
the law, management does not believe that any of these actions or claims are
material. However, these actions against the Company are subject to the
uncertainties inherent in any litigation.

5. SUBSEQUENT EVENT

On October 13, 1999, The Statoil Group -- Norway ("Statoil") announced
plans to seek a buyer for its U.S. natural gas and electric power production and
marketing unit, Statoil Energy, Inc. ("STEN") in connection with a corporate
restructuring process. The Statoil Group has announced its intentions to market
STEN as an integrated enterprise consisting of STEN's subsidiaries, including
Eastern States, involved in gas production, power production, energy marketing
and energy trading. However, the Statoil Group may determine that the sale of
individual assets or divisions, including Eastern States, is more appropriate.
If such a sale of Statoil Energy or Eastern States occurs, the Company cannot
assure that it will not adversely affect Eastern States.

6. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

Proved oil and natural gas reserves of the Underlying Properties have been
estimated by Ryder Scott Company, L.P., independent petroleum engineers as of
August 31, 1999. Reserves for the years ended December 31, 1998 and 1997 were
internally prepared by the Company's petroleum engineers. Since the Company does
not have comparable reserve reports for periods prior to December 31, 1997 due
to its property acquisitions in 1996 and 1997, such estimates prior to December
31, 1997 have been internally developed by the Company's petroleum engineers by
adding back actual production volumes to arrive at estimated reserve balances at
December 31, 1995 and 1996. As a result of this method, the following tables
reflect no reserve estimate revisions for periods prior to 1998. Drilling
activities on these properties during 1996 and 1997 have represented development
of these proved reserves. The reserve estimates provided for the Underlying
Properties were calculated before the effects of conveying the Net Profits
Interests to the Trust. In accordance with Statement of Financial Accounting
Standards No. 69, estimates of future net revenues from proved reserves have
been prepared using year-end oil and natural gas prices and current costs to
produce and develop the proved reserves, excluding overhead. The standardized
measure of future net cash flows from oil and natural gas reserves is calculated
based on discounting such future net cash flows at an annual rate of 10%.
Year-end oil prices were $22.50 per barrel for 1996, $15.00 per barrel for 1997
and $9.00 per barrel for 1998. As of August 31, 1999, oil prices were $18.75 per
barrel. Year-end weighted average natural gas prices were $3.68 per Mcf for
1996, $2.57 per Mcf for 1997 and $2.71 per Mcf for 1998. As of August 31, 1999,
the weighted average natural gas price was $2.75 per Mcf.

F-5
84

UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND

DIRECT OPERATING EXPENSES -- (CONTINUED)

6. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)

PROVED RESERVES GAS (MMCF) OIL (MBBLS)
- --------------- ---------- -----------

Balance, December 31, 1995.................................. 666,996 338
Revisions................................................. -- --
Extensions, discoveries and other additions............... 6,094 --
Production................................................ (19,318) (35)
Balance, December 31, 1996.................................. 653,772 303
Revisions................................................. -- --
Extensions, discoveries and other additions............... 11,167 --
Production................................................ (19,960) (31)
Balance, December 31, 1997.................................. 644,979 272
Revisions................................................. 63,187 20
Extensions, discoveries and other additions............... -- --
Production................................................ (19,040) (20)
Balance, December 31, 1998.................................. 689,126 272
Revisions................................................. 88,955 7
Extensions, discoveries and other additions............... -- --
Production................................................ (11,967) (19)
Balance, August 31, 1999.................................... 766,114 260

PROVED DEVELOPED RESERVES

GAS (MMCF) OIL (MBBLS)
---------- -----------

December 31, 1995........................................... 360,942 338
December 31, 1996........................................... 347,718 303
December 31, 1997........................................... 338,925 272
December 31, 1998........................................... 344,907 272
August 31, 1999............................................. 329,581 260

F-6
85

UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND

DIRECT OPERATING EXPENSES -- (CONTINUED)

6. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)

The standardized measure of future net cash flows is not intended to
represent the fair value of the Underlying Properties. Numerous uncertainties
are inherent in estimating volumes and values of proved reserves and in
projecting future production rates and timing of development expenditures. Such
reserve estimates are subject to change as additional information becomes
available. The reserves actually recovered and the timing of production may be
substantially different from the original estimates. Also, because natural gas
prices are influenced by seasonal demand, use of year-end prices, as required by
the Financial Accounting Standards Board, may not be representative in
estimating future revenues or reserve data.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
RESERVES
(IN THOUSANDS)

YEARS ENDED DECEMBER 31, EIGHT MONTHS
------------------------------------- ENDED AUGUST 31,
1996 1997 1998 1999
----------- ---------- ---------- ----------------

Future cash inflows...................... $ 2,320,789 $1,669,303 $1,874,485 $2,129,626
Future costs:
Production............................. (360,827) (313,269) (322,418) (373,705)
Development............................ (182,412) (172,966) (189,211) (284,973)
----------- ---------- ---------- ----------
Future net cash flows.................... 1,777,550 1,183,068 1,362,856 1,470,948
10% discount factor...................... (1,234,237) (821,460) (975,895) (1,103,671)
----------- ---------- ---------- ----------
Standardized measure of discounted future
net cash flows......................... $ 543,313 $ 361,608 $ 386,961 $ 367,277
=========== ========== ========== ==========

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED
RESERVES
(IN THOUSANDS)

YEARS ENDED DECEMBER 31, EIGHT MONTHS
------------------------------- ENDED AUGUST 31,
1996 1997 1998 1999
-------- --------- -------- ----------------

Standardized measure, beginning of period..... $367,873 $ 543,313 $361,608 $386,961
Revisions:
Prices and costs............................ 157,764 (174,524) 27,273 6,346
Quantity estimates.......................... -- -- 40,544 50,828
Accretion of discount....................... 53,688 54,732 29,835 31,078
Production rates and other.................. (4,978) (35,532) (21,242) 8,912
-------- --------- -------- --------
Net revisions............................ 206,474 (155,324) 76,410 97,164
Extensions, discoveries and other additions... 6,860 7,235 -- --
Production.................................... (44,075) (42,856) (34,665) (21,085)
Development costs............................. 6,181 9,240 (16,392) (95,763)
-------- --------- -------- --------
Net change............................... 175,440 (181,705) 25,353 (19,684)
-------- --------- -------- --------
Standardized measure, end of period........... $543,313 $ 361,608 $386,961 $367,277
======== ========= ======== ========

F-7
86

REPORT OF INDEPENDENT AUDITORS

Board of Directors and Stockholder
Eastern States Oil & Gas, Inc.

We have audited the accompanying statement of assets and trust corpus of
the Appalachian Natural Gas Trust (formerly the Appalachian Basin Royalty Trust)
as of August 19, 1999. This financial statement is the responsibility of the
management of Eastern States Oil & Gas, Inc. Our responsibility is to express an
opinion on this financial statement based on our audit.

We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statement is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statement. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the statement referred to above presents fairly, in all
material respects, the assets and trust corpus of the Appalachian Natural Gas
Trust as of August 19, 1999, in conformity with generally accepted accounting
principles.

ERNST & YOUNG LLP

Vienna, Virginia

August 23, 1999, except for Note 2, as

to which the date is October 13, 1999

F-8
87

APPALACHIAN NATURAL GAS TRUST

STATEMENT OF ASSETS AND TRUST CORPUS

AS OF AUGUST 19, 1999

Cash........................................................ $1,000
======
Trust Corpus................................................ $1,000
======

See Accompanying Notes to Statement of Assets and Trust Corpus.

F-9
88

APPALACHIAN NATURAL GAS TRUST

NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS

1. TRUST ORGANIZATION

Appalachian Natural Gas Trust, formerly the Appalachian Basin Royalty Trust
(the "Trust"), is a grantor trust that was created on August 18, 1999 by Eastern
States Oil & Gas, Inc. (the "Company"), a wholly owned subsidiary of Statoil
Energy Holdings, Inc. The Statement of Assets and Trust Corpus reflects the
Company's initial cash contribution to the Trust of $1,000.

The Trust was formed to hold net profits interests entitling it to 80% of
the net proceeds received by the Company from the sale of oil and natural gas
from 2,471 producing wells in Kentucky and West Virginia and 10% of the net
proceeds received by the Company from the sale of oil and natural gas in certain
undeveloped properties in Kentucky and West Virginia (the "Underlying
Properties"). These net profits interests will be conveyed to the Trust by the
Company upon completion of a successful public offering of beneficial interests
("Units") in the Trust.

The Trust will terminate upon the first occurrence of: (a) disposition of
all net profits interests pursuant to terms of the Trust Agreement, (b) when net
proceeds attributable to the Underlying Properties are less than $3.5 million
per year for each of two successive years after the year 2000 in the state of
West Virginia or less than $3.5 million per year for each of two successive
years after the year 2000 in the state of Kentucky, or (c) a vote of at least
66 2/3% of the Trust Unitholders to terminate the Trust in accordance with
provisions of the Trust Agreement. These termination clauses will be finalized
upon execution of the Trust Conveyance Agreement.

2. SUBSEQUENT EVENT

F-10
89

APPALACHIAN NATURAL GAS TRUST

UNAUDITED PRO FORMA STATEMENT OF ASSETS

AND TRUST CORPUS AS OF SEPTEMBER 1, 1999

(IN THOUSANDS)

Cash...................................................... $ 1
Oil and Gas Property...................................... 210,000
--------
$210,001
========
Trust Corpus.............................................. $210,001
========

NOTE -- BASIS OF PRESENTATION

Appalachian Natural Gas Trust (the "Trust"), formerly the Appalachian Basin
Royalty Trust, is a grantor trust that was created on August 18, 1999 by Eastern
States Oil & Gas, Inc. (the "Company"), a wholly owned subsidiary of Statoil
Energy Holdings, Inc. The Statement of Assets and Trust Corpus reflects the
Company's initial cash contribution to the Trust of $1,000.

F-11
90

APPALACHIAN NATURAL GAS TRUST

UNAUDITED PRO FORMA STATEMENT OF DISTRIBUTABLE CASH
FOR THE YEAR ENDED DECEMBER 31, 1998 AND

FOR THE EIGHT MONTHS ENDED AUGUST 31, 1999

(IN THOUSANDS)

EIGHT MONTHS
YEAR ENDED ENDED
DECEMBER 31, AUGUST 31,
1998 1999
------------ ----------------

Revenue:
Gas sales................................................. $41,835 $25,594
Oil sales................................................. 242 230
------- -------
Total revenues.................................... 42,077 25,824
------- -------
Direct Operating Expenses:
Taxes on production and property.......................... 3,809 2,338
Production expenses....................................... 3,603 2,401
------- -------
Total expenses.................................... 7,412 4,739
------- -------
Excess of Revenues over Direct Operating Expenses........... 34,665 21,085
------- -------
Pro Forma Adjustments (Note 2):
Revenue................................................... (2,439) (1,533)
Production expenses....................................... (897) (599)
Overhead.................................................. (1,870) (1,250)
------- -------
Total pro forma adjustments....................... (5,206) (3,382)
------- -------
Pro Forma Net Proceeds(1)................................... 29,459 17,703
Net Profits Interests Percentage............................ 80% 80%
------- -------
Trust Cash.................................................. 23,567 14,162
Less Trust General and Administrative Expenses.............. (300) (200)
------- -------
Distributable Cash.......................................... $23,267 $13,962
======= =======

- ---------------

(1) There were no development costs for the period January 1, 1998 through
August 31, 1999, since all wells drilled by the Company during that period
were excluded from the Underlying Properties. The Company expects to incur
development costs averaging approximately $4.4 million per year, net to the
Trust, for at least the next five years, which will reduce distributable
cash by a corresponding amount per Unit.

See Accompanying Notes to Pro Forma Statement of Distributable Cash.

F-12
91

APPALACHIAN NATURAL GAS TRUST

NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE CASH
(UNAUDITED)

1. BASIS OF PRESENTATION

Appalachian Natural Gas Trust (the "Trust") was created in August 1999 by
Eastern States Oil & Gas, Inc. (the "Company"). The Company will convey certain
net profits interests (the "Net Profits Interests") from the Underlying
Properties to the Trust in exchange for all of the units of beneficial interest
in the Trust.

The pro forma statement of distributable cash of the Trust for the year
ended December 31, 1998 and eight months ended August 31, 1999 has been prepared
from the historical statement of revenues and direct operating expenses of the
Underlying Properties, adjusted, and based on the following assumptions:

a.The Trust was formed and the Net Profits Interests were conveyed to the
Trust prior to January 1, 1998.

b.Distributable cash of the trust is calculated based on the gross proceeds
from the Underlying Wells. For the period presented there is no pro forma
distributable cash attributable to the 10% net profits interest since all
wells drilled by Eastern States during this time period are excluded from
the Underlying Properties. Net Proceeds is a defined term in the Net
Profits Interests conveyances to the Trust.

c.Administrative expense is estimated to be $300,000 annually. Such expense
generally would include Trustee fees and costs incurred by the Trustee to
administer the Trust and report Trust results to Unitholders, including
the expense of attorneys, independent auditors, reservoir engineers,
printing and mailing.

2. PRO FORMA ADJUSTMENTS

The following pro forma adjustments were made to the historical revenues
and direct operating expenses of the Underlying Properties to present Trust pro
forma distributable cash for the year ended December 31, 1998 and eight months
ending August 31, 1999:

a.The Net Profits Interest conveyances to the Trust provide for the Company
to receive gathering and compression fees which cover actual costs
incurred plus depreciation and to provide a return on invested capital.
The adjustment to record depreciation and return on invested capital is
reflected as a reduction to revenue in the pro forma statement.

b.The conveyances to the Trust will provide for the Company to charge
production expenses at fixed rates, subject to adjustment, which exceed
actual costs incurred by the Company. Such additional charges are shown
as an increase in production expenses in the pro forma statement.

c.A Company overhead charge of $1,870,000 and $1,250,000 for the year ended
December 31, 1998 and eight months ended August 31, 1999, respectively,
were deducted. The overhead charge is based on a monthly count of active
wells operated by the Company and is specified by the terms of the Net
Profits Interests conveyances to the Trust.

3. FEDERAL INCOME TAXES

As a grantor trust, the Trust will not be required to pay federal income
taxes. Accordingly, the accompanying pro forma statement of distributable income
does not include a provision for federal income taxes.

F-13
92

APPALACHIAN NATURAL GAS TRUST

NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE CASH -- (CONTINUED)
(UNAUDITED)

4. CONTINGENCIES

The Company is involved in various legal actions and claims arising in the
normal course of business. Based upon its current assessment of the facts and
the law, management does not believe that the outcome of any such action or
claim will have a material adverse effect upon the value of the underlying
properties. However, these actions against the Company are subject to the
uncertainties inherent in any litigation.

5. PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

Proved oil and natural gas reserves of the Trust have been estimated as of
August 31, 1999 by Ryder Scott Company, L.P., independent petroleum engineers.
In accordance with Statement of Financial Accounting Standards No. 69, estimates
of future net revenues from proved reserves have been prepared using year-end
oil and natural gas prices and current costs to produce and develop the proved
reserves. The standardized measure of future net cash flows from oil and natural
gas reserves is calculated based on discounting such future net cash flows at an
annual rate of 10%. Crude oil prices were $18.75 per barrel at August 31, 1999.
The weighted average spot gas price was $2.61 per Mcf at August 31, 1999. Since
the Trust is not subject to taxation at the trust level, no provision is
included for federal income taxes.

Reserve quantities and revenues for the Net Profits Interests were
estimated from projections of reserves and revenues attributable to the
Underlying Properties. Since the Trust has a defined Net Profits Interest, the
Trust does not own a specific ownership percentage of the oil and natural gas
reserves or production quantities. Accordingly, reserves and production
allocated to the Trust pertaining to its interests in 80% of the net cash
proceeds from the underlying wells and 10% of the net cash proceeds from the
undeveloped properties have effectively been reduced to reflect recovery of the
Trust's 80% and 10% portion, respectively, of applicable production and
development costs, excluding overhead and trust administrative expenses. Because
Trust reserve quantities are determined using an allocation formula, any
fluctuations in actual or assumed prices or costs will result in revisions to
the estimated reserve quantities allocated to the Net Profits Interests.

The Net Profits Interests' share of production and development costs have
been deducted in calculating distributable cash attributable to the Net Profits
Interests. Accordingly, these costs are not shown separately as future costs in
calculating the standardized measure. Only production taxes, calculated at the
same rate as incurred on the Underlying Properties, is included in future
production costs in calculating the standardized measure.

The standardized measure of future net cash flows is not intended to
represent the fair value of the Trust. Numerous uncertainties are inherent in
estimating volumes and values of proved reserves and in projecting future
production rates and timing of development expenditures. Such reserve estimates
are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production may be substantially different
from the original estimates. Also, because natural gas prices are influenced by
seasonal demand, use of year-end prices, as required by the Financial Accounting
Standards Board, may not be representative in estimating future revenues or
reserve data.

NATURAL GAS (MCF) OIL (BBLS)
----------------- ----------
(IN THOUSANDS)

PROVED RESERVES
Balance, August 31, 1999.................................... 239,101 171
PROVED DEVELOPED RESERVES
August 31, 1999............................................. 210,018 171

F-14
93
APPALACHIAN NATURAL GAS TRUST

NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE CASH -- CONTINUED
(UNAUDITED)

5. PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION -- (CONTINUED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

RELATING TO PROVED RESERVES AT AUGUST 31, 1999

(IN THOUSANDS)

Future cash inflows......................................... $ 628,249
Future production taxes and development..................... (51,042)
---------
Future net cash flows....................................... 577,207
10% discount factor......................................... (376,787)
---------
Standardized measure of discounted future net cash flows.... $ 200,420
=========

F-15
94
APPENDIX A

INFORMATION ABOUT
EASTERN STATES OIL & GAS, INC.

THE TRUST UNITS ARE NOT INTERESTS IN OR OBLIGATIONS OF
EASTERN STATES OIL & GAS, INC.
95

EASTERN STATES OIL & GAS, INC.

Eastern States Oil & Gas, Inc. is an independent energy company engaged in
the development, production, acquisition, marketing, gathering and
transportation of natural gas and oil in the Appalachian Basin. Eastern States
is the largest owner of proved natural gas reserves in the Appalachian Basin.
Substantially all of our natural gas and oil reserves are located in Kentucky,
Ohio and West Virginia. We also have properties in Indiana, Maryland, Michigan
and Virginia.

Since its inception in 1994, Eastern States has grown through developmental
drilling and acquisitions of natural gas and oil producing properties. During
this period, we spent approximately $650 million on 16 acquisitions, including
the acquisition of Blazer Energy Corp., formerly Ashland Exploration, Inc., in
July 1997. The acquisition of Blazer Energy increased our estimated proved
reserves in the Appalachian Basin by approximately 769 Bcfe. Eastern States and
Blazer have since combined their assets in the Appalachian Basin.

For the years ended December 31, 1996, 1997 and 1998, Eastern States had
total revenue of $18.2 million, $65.4 million and $104.7 million, and for the
first six months of 1999, we had total revenues of $57.7 million. For the years
ended December 31, 1996, 1997 and 1998, Eastern States had net income of $3.9
million, $9.2 million and $8.3 million, and for the first six months of 1999, we
had net income of $6.0 million.

Eastern States currently owns and operates over 5,700 gross wells in the
Appalachian Basin. At December 31, 1998, Eastern States' estimated net proved
reserves were 1,062 Bcfe, of which 709 Bcfe, or 67%, were proved developed. The
estimated discounted future net cash flows of Eastern States' proved reserves,
before United States income taxes, were $675 million as of December 31, 1998.
For the six months ended June 30, 1999, total average net sales meter natural
gas and oil production was 104 MMcfe per day, of which 98% was natural gas.

Eastern States is continually evaluating oil and natural gas properties and
other investment opportunities in addition to its development and operation of
existing properties, including the underlying properties.

Eastern States is an indirect wholly owned subsidiary of Statoil Energy,
Inc. Statoil Energy also:

- owns and operates power plants throughout the northeast and the
mid-Atlantic region;

- is a leading trader of wholesale electricity and natural gas;

- specializes in providing a broad range of energy and risk management
services involving the delivery of natural gas, electricity and
alternative fuels to large industrial, institutional and commercial
customers; and

- through its indirect wholly owned subsidiary, Eastern States Exploration
Company, owns and operates approximately 600 wells in Pennsylvania, with
estimated net proved reserves of 39 Bcfe at December 31, 1998 and an
average daily net sales meter production of 6 MMcfe for the six months
ended June 30, 1999. Eastern States does not own any interest in Eastern
States Exploration Company.

Statoil Energy is currently an indirect wholly owned U.S. subsidiary of the
Norwegian state oil company "den norske stats oljeselskap a.s" which is also
known as The Statoil Group. The Statoil Group has substantial ongoing
commitments associated with various development projects worldwide and has
numerous international investment opportunities competing for limited capital.
Based upon those capital commitments, various assets and interests, including
Statoil Energy, were evaluated for strategic ranking, possible sale or joint
venture. Based upon that evaluation, The Statoil Group concluded that it was
unable to continue to fund Statoil Energy's planned increase of the scale of its
operations and targeted it for a possible joint venture.

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None of The Statoil Group, Statoil Energy or Eastern States can provide
assurance that such a sale will be made or when such a sale might be concluded.
While The Statoil Group is currently exploring the possible sale of Statoil
Energy and its subsidiaries, including Eastern States, The Statoil Group may
determine that the sale of individual assets or divisions, including Eastern
States, is more appropriate. If a sale of Statoil Energy or Eastern States is
made, there is no assurance that it would not adversely affect Eastern States.
However, any successor to Eastern States would be subject to the obligations of
Eastern States under the transfer documents and the Trust Agreement described in
the main part of this prospectus.

BY PURCHASING TRUST UNITS YOU WILL NOT ACQUIRE AN OWNERSHIP INTEREST IN ANY
OF EASTERN STATES, STATOIL ENERGY OR THE STATOIL GROUP.

Eastern States is a Delaware corporation. Its principal executive offices
are located at 2800 Eisenhower Avenue, Alexandria, Virginia 22314 and the
telephone number is (703) 317-2300.

RISK FACTORS APPLICABLE TO EASTERN STATES

NATURAL GAS PRICE DECLINES AND MARKET VOLATILITY COULD ADVERSELY AFFECT OUR
FINANCIAL RESULTS.

Even relatively modest changes in natural gas prices may significantly
change our revenues, results of operations, cash flows and value of proved
reserves. The markets for natural gas have been volatile and are likely to
continue to be volatile in the future. Natural gas prices can fluctuate widely
in response to relatively minor changes in the supply of and demand for natural
gas, market uncertainty and a variety of additional factors that are beyond our
control, such as:

- weather conditions, primarily in the northeast United States;

- the supply and price of domestic and foreign natural gas and oil;

- delivery interruptions by upstream pipeline companies;

- the level of demand;

- worldwide economic and political conditions;

- the price and availability of alternative fuels;

- environmental regulations; and

- worldwide energy conservation measures.

Moreover, government regulations, such as regulation of natural gas
transportation or price controls, if imposed, could affect product prices in the
long term.

Natural gas produced in the Appalachian Basin has historically received a
premium over natural gas produced in other regions due to the region's close
proximity to the markets in the northeast United

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States. For the period 1991 through 1998, natural gas price indices for
Appalachian Basin production have averaged $0.25 per MMbtu more than prices for
natural gas contracts traded on the NYMEX for the delivery of natural gas at
Henry Hub, Louisiana. During these eight years, the average annual Appalachian
Basin premium has ranged from $0.14 per MMbtu to $0.47 per MMbtu. Any material
decrease in this average premium could have an adverse impact on the proceeds
received from the sale of natural gas by Eastern States.

WE MAY NOT BE ABLE TO OBTAIN ADEQUATE FINANCING TO EXECUTE OUR OPERATING
STRATEGY.

Our business is capital intensive and, to maintain our base of proved gas
reserves, a significant amount of cash flow from operations must be invested in
development activities. We make substantial capital expenditures for the
development, acquisition and production of natural gas reserves. Historically,
we have financed these expenditures primarily from the following sources:

- cash generated by operations;

- bank borrowings; and

- loans and capital contributions from The Statoil Group.

Our management believes that we will have sufficient cash generated from
operations to fund planned capital expenditures through at least the year 2000.
If our revenues significantly decrease as a result of lower natural gas prices,
operating difficulties or declines in reserves, we may not be able to expend the
capital necessary to undertake or complete future development programs or
acquisition opportunities. Without these timely investments, our gas production
and reserves will decline.

LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS.

Our outstanding indebtedness under the promissory note with Statoil Energy
Holdings, Inc., an indirect subsidiary of the Statoil Group, was $505 million at
September 30, 1999 and matures on December 31, 2001. Our intercompany
indebtedness with affiliates of Statoil Energy at September 30, 1999 was
approximately $51 million. Our ability to meet our debt service obligations and
reduce our total indebtedness will depend on our future performance. Our future
performance, in turn, depends on many factors that are beyond our control such
as general economic, financial and business conditions. We cannot assure you
that economic conditions and financial, business and other factors will not
adversely affect our future performance.

ESTIMATES OF NATURAL GAS RESERVES ARE UNCERTAIN.

The calculations of proved reserves of natural gas and oil included in this
appendix are only estimates. These estimates were prepared by Eastern States and
reviewed by Ryder Scott Company, L.P., independent petroleum engineers. The
accuracy of any reserve estimate is a function of the quality of available data,
engineering and geological interpretation and judgment, and the assumptions used
regarding quantities of recoverable natural gas and natural gas prices. Actual
prices, production, development expenditures, operating expenses and quantities
of recoverable oil and natural gas reserves will vary from those we assume in
our estimates, and those variances may be significant. Any significant variance
from the assumptions used could result in the actual quantity of our reserves
and future net cash flow being materially different from the estimates in our
review reports. In addition, results of drilling, testing and production and
changes in crude oil, natural gas liquids and natural gas prices after the date
of the estimate may result in substantial upward or downward revisions.

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WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES.

Without successful exploration, development or acquisition activities, our
reserves and revenues will decline over time. The continuing development of
reserves, acquisition activities and, to a lesser extent, exploration, will
require significant expenditures. If our cash flow from operations is not
sufficient for this purpose, we may not be able to obtain the necessary funds
from other sources.

WE MAY NOT BE SUCCESSFUL IN DRILLING NEW WELLS.

We currently anticipate drilling an average of approximately 200 to 230 new
wells per year in Kentucky and West Virginia for at least the next five years.
We cannot assure you that any of the new wells will be successful or produce in
commercial quantities or that we will be able to drill approximately 200 to 230
new wells per year.

FACILITIES MAINTENANCE ON THIRD PARTY PIPELINE DELIVERY SYSTEMS COULD CREATE
INTERRUPTIONS IN THE DELIVERY OF NATURAL GAS WE PRODUCE.

We depend on the availability of third party pipeline delivery systems to
transport over 90% of our natural gas. Any interruptions in the availability of
these systems due to facilities maintenance requirements or other extraordinary
events could inhibit our ability to sell our natural gas. For example, Columbia
Transmission Corp. has shut down one of its pipelines in Kentucky from September
27, 1999 to November 15, 1999 for replacement of a portion of its pipeline
system. This temporary shut-down will delay the delivery and sale of
approximately 30% of Eastern States' natural gas production in Kentucky.

WE MAY NOT INSURE AGAINST ALL HAZARD LOSSES.

We insure against some, but not all, of the hazards associated with the
natural gas industry. For example, we are not insured against the following
hazards:

- fines and penalties;

- pollution events occurring prior to Eastern States' acquisition date;

- professional errors and omissions of engineers, geologists and surveyors;

- loss or unrecoverability of oil and natural gas reserves;

- loss of downhole equipment;

- loss of income due to third party failure to provide equipment or
materials; and

- war and associated events of civil unrest.

As a result, we may be exposed to liability or losses that could be substantial
due to events that we do not insure.

HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.

In order to manage our exposure to price risks in the marketing of our gas,
we enter into hedging arrangements relating to a portion of our expected
production. In the past, these hedges have involved a number of arrangements at
a variety of fixed prices and other provisions, including price floors and
ceilings. In the future, we may enter into natural gas futures contracts,
options, collars and swaps. Our hedging activities are subject to a number of
risks, including instances in which:

- production is less than expected;

- there is a widening of price differentials between delivery points
required by fixed price delivery contracts to the extent they differ from
those on our production; or

- counterparties to our futures contract are unable to meet the financial
terms of the transaction.

While hedging arrangements limit the risk of declines in natural gas
prices, they may also limit the extent to which we benefit from increases in the
price of natural gas.

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WE MAY INCUR SUBSTANTIAL COSTS TO COMPLY WITH ENVIRONMENTAL AND OTHER
GOVERNMENTAL REGULATIONS.

Environmental and other governmental regulations have increased the costs
to plan, design, drill, install, operate and abandon oil and natural gas wells
and other facilities. Increasingly strict environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property, employees,
other persons and the environment resulting from our operations, could result in
substantial costs and liabilities in the future.

FORWARD-LOOKING STATEMENTS

This appendix contains forward-looking statements relating to Eastern
States' operations and the oil and gas industry. Such forward-looking statements
are based on management's current projections and estimates and are identified
by words such as "expects," "intends," "plans," "projects," "anticipates,"
"believes," "estimates" and similar words. These statements are not guarantees
of future performance and involve risks, uncertainties and assumptions that are
difficult to predict. Therefore, actual results may differ materially from what
is expressed or forecasted in such forward-looking statements.

Among the factors that could cause actual results to differ materially are:

- natural gas and oil price fluctuations;

- the availability of funds for our future development programs and
acquisitions;

- the results of our development program;

- potential delays or failure to achieve expected production from existing
and future exploitation and development projects;

- potential disruption of operations because of our failure or the failure
of others with whom we have material relationships to achieve timely Year
2000 compliance; and

- potential liability resulting from pending or future litigation.

In addition, these forward-looking statements may be affected by general
domestic and international economic and political conditions.

BUSINESS AND PROPERTIES

HISTORICAL DEVELOPMENT OF OUR BUSINESS

Eastern States was organized in April 1994 to engage in the acquisition,
exploration and development of natural gas, oil and other mineral interests.
Eastern States has developed a significant reserve base, primarily through:

- acquisitions of proved natural gas and oil reserves and undeveloped
leaseholds;

- strategic acquisitions of other companies engaged in the development and
production of natural gas and oil; and

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- development and exploitation of these leaseholds and acquired properties
through drilling, recompletions of existing wells and construction of
pipelines and compression projects.

Our estimated net proved reserves increased from 38 Bcfe at December 31,
1994 to 1,062 Bcfe at December 31, 1998. Our average daily production increased
from 2 MMcfe per day at December 31, 1994 to over 100 MMcfe per day at December
31, 1998. Our acquisitions have added a total of approximately 900 Bcfe to our
reserve base. Additionally, we have expended a total of $81 million to drill 418
net wells during the last five years, developing approximately 114 Bcfe of net
proved developed reserves. Approximately 97% of our wells drilled during this
five-year period were completed as producing wells. The direct finding costs for
our drilling program averaged $0.71 per Mcfe during the same period.

Acquisitions. Since our formation, we have made a series of acquisitions of
natural gas and oil producing properties, including the following:

- In August 1994, we acquired natural gas and oil properties, including
gathering lines, in West Virginia and Kentucky from Southeastern Gas
Company for approximately $17 million in cash.

- In April 1996, we acquired natural gas and oil properties, including
gathering lines, in West Virginia from CNG Transmission Company for
approximately $16 million in cash.

- In May 1996, we acquired natural gas and oil properties, including
gathering lines, in Ohio from General Motors Corporation for
approximately $34 million in cash.

- In July 1997, we acquired Blazer Energy for approximately $567 million in
cash. Immediately thereafter, we sold Blazer Energy's Gulf of Mexico
properties to our affiliate Statoil Exploration U.S., Inc., an indirect
wholly owned subsidiary of The Statoil Group, for approximately $82
million. In 1998, we sold a portion of Blazer Energy's proved developed
reserves, along with undeveloped acreage, located outside the Appalachian
Basin to Whiting Petroleum Corporation and BWAB Incorporated for
approximately $24 million.

Appalachian Natural Gas Trust. In August 1999, Eastern States formed the
Appalachian Natural Gas Trust, which will hold net profits interests in the
Appalachian Basin area of Kentucky and West Virginia. The net profits interests
will entitle the trust to receive:

- 80% of the net proceeds received by Eastern States from the sale of
natural gas from 2,471 producing wells owned by Eastern States in
Kentucky and West Virginia; and

- 10% of the net proceeds received by Eastern States from the sale of
natural gas from all wells drilled after September 1, 1999 in the leases
in Kentucky and West Virginia that are subject to the net profits
interests.

The net profits interests to be contributed to the trust contain
approximately 240 Bcfe of proved reserves.

Eastern States will receive all of the net cash proceeds from the sale of
trust units in an underwritten public offering, which proceeds are currently
estimated to be approximately $146.5 million before expenses of the offering,
assuming the underwriters do not exercise their over-allotment option. We intend
to use the net proceeds of the offering to repay a portion of the existing
indebtedness to Statoil Energy Holdings.

OUR BUSINESS STRATEGY

Our business strategy is to increase cash flow by increasing both our
reserves and production through:

- the development and exploitation of existing properties; and

- the selective acquisition of additional properties with development and
exploitation potential.

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Enhancing Our Appalachian Basin Position

We are continuing to develop our large leasehold position in the
Appalachian Basin, where we own approximately 1.4 million gross acres and 1,158
proved undeveloped drilling locations at December 31, 1998. We currently expect
to drill 200 to 230 wells per year for at least the next five years, which is
expected to require approximately $44 million to $50 million per year in capital
spending. Our level of capital expenditures may vary in the future depending on
a number of factors, including energy market conditions, availability and
reliability of supplies of goods and services and costs in comparison to
expected rates of return.

Pursuing Growth Through Targeted Acquisitions

We are continually evaluating opportunities to acquire producing and
undeveloped properties that possess, among others, one or more of the following
characteristics:

- close proximity to our existing operations;

- potential opportunities to increase reserves through production
enhancement of existing reserves and the discovery of reserves on
undeveloped properties; and

- potential opportunities to reduce production expenses through more
efficient operations.

Our multi-disciplined due diligence teams have evaluated approximately 100
acquisition opportunities during the past five years. These same teams have also
been directly involved in the assimilation, exploration and development of
acquired properties. We believe this continuity and focus as well as our
established operating presence will enhance our competitive ability to complete
future acquisitions.

PROPERTIES AND DEVELOPMENT ACTIVITIES

At December 31, 1998, we estimated our total estimated net proved reserves
at 1,062 Bcfe. Estimated net proved developed reserves were 709 Bcfe,
representing 67% of our total net proved reserves. Except for one producing well
located in the Michigan Basin, all of our estimated net proved reserves are
located in the Appalachian Basin. All information in this appendix relating to
estimated natural gas and oil reserves and the estimated future net cash flows
before taxes attributable to those reserves is based on estimates prepared by us
that have been reviewed by Ryder Scott Company, L.P., independent petroleum
engineers. Under a review report, the independent petroleum engineers review
estimates prepared by a company's engineering staff. The following table
summarizes our estimated net proved reserves as of December 31, 1998, in each
state in which we own proved reserves, based on the standardized measure before
United States income taxes as of December 31, 1998. The standardized measure
does not include the value of Section 29 tax credits attributable to Devonian
Shale and tight sands natural gas properties and future plugging and abandonment
liabilities. See "-- Section 29 Tax Credits."

DECEMBER 31, 1998 PROVED RESERVES
------------------------------------------------------------------
NATURAL % OF TOTAL
GAS TOTAL STANDARDIZED STANDARDIZED
STATE (MMCF) OIL (MBBLS) (MMCFE) MEASURE MEASURE
- ----- --------- ----------- --------- ------------- ------------
(IN MILLIONS)

West Virginia.................... 583,037 345 585,112 $364 54%
Kentucky......................... 394,812 62 395,184 258 38%
Ohio............................. 57,933 1,585 67,440 41 6%
Other including proved reserves
located in Maryland, Michigan
and Virginia................... 13,932 12 14,002 12 2%
--------- ----- --------- ---- ---
Total.................. 1,049,714 2,004 1,061,738 $675 100%

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At December 31, 1998, we had identified 1,158 additional proved undeveloped
drilling locations, many of which will be drilled as part of our planned
drilling programs over the next five years. For the period January 1, 1998 to
June 30, 1999, approximately 40% of all wells drilled by Eastern States were on
locations classified as unproved at the time of drilling. Our total net gas
production from the Appalachian Basin in 1998 averaged approximately 100 MMcf
per day, with minimal associated oil or water production. We have an average
working interest of approximately 94% in our wells in the Appalachian region,
which represents an approximately 84% average net revenue interest.

Natural gas produced in the Appalachian Basin has historically received a
premium over natural gas produced in other regions due to the region's close
proximity to the major gas consuming markets in the northeastern United States.
For the period 1991 through 1998, wellhead natural gas prices in the Appalachian
Basin have averaged on an annual basis $0.25 per MMbtu more than the Henry Hub
and NYMEX wellhead natural gas prices. During these eight years, the average
annual Appalachian Basin premium has ranged from $0.14 per MMbtu to $0.47 per
MMbtu. In addition, natural gas produced by Eastern States also typically
receives an "energy content" premium since it contains an average of 1,116 Btu
per cubic foot as compared to NYMEX prices which are quoted based on 1,000 Btu
per cubic foot. The Appalachian Basin premium is typically lower during
warmer-than-normal winters, such as the previous two winters.

Eastern States will transfer to the trust, effective as of September 1,
1999:

- an 80% net profits interest in 2,471 producing natural gas wells in
Kentucky and West Virginia; and

- a 10% net profits interest in substantially all of its current oil and
gas leasehold interests in Kentucky and West Virginia.

Eastern States will retain the following:

- rights to the Rome exploration area in Kentucky and West Virginia;

- leases farmed out to third parties;

- leases with known transfer or title issues, including all potential
coalbed methane exploration and development rights;

- Section 29 credit wells;

- wells drilled during the 20 months ended August 31, 1999;

- wells with title issues;

- wells with high operating costs;

- marginal producing wells; and

- wells in which Eastern States is not the operator.

The Appalachian Basin is the oldest and geographically one of the largest
natural gas producing regions in the United States. As of June 30, we operated
over 5,700 gross, or 5,400 net, wells, 3,500 miles of gathering pipelines and
104 compressor stations in 47 counties in five states in the region. Our wells
in the Appalachian Basin produce from geologic formations that are Pennsylvanian
to Cambrian in age. Our wells range from 1,000 to 8,000 feet, with an average
depth of approximately 5,000 feet. Individual wells often have economic lives of
up to 50 years. The costs to develop Appalachian Basin reserves are low compared
to other regions of the United States because of the relatively shallow
reservoir depths and the low incidence of dry holes. Over the past five calendar
years, we have drilled 418 net wells in the Appalachian region, with a 97%
completion rate.

Our wells in the Appalachian Basin are characterized by a relatively high
reserve-to-production ratio of over 27 years and a low natural production
decline rate averaging 7% to 8% for the first five years. Reserves in the
Appalachian Basin have a high degree of development success, that is, as
development

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progresses reserves are reclassified from the unproved to the proved category
and additional layers of offset reserves are added as proved undeveloped
reserves.

We believe that we realize operational efficiencies and therefore are able
to maximize the return on our investment in the Appalachian Basin because of:

- our large acreage position;

- our substantial ongoing development program conducted over a number of
years and the experience and expertise gained from these activities; and

- our extensive gas gathering system.

Our Appalachian gas gathering system is interconnected with various
intrastate and interstate transmission lines that allow access to both local and
major markets in the northeastern United States. Some of our Appalachian natural
gas production is connected directly to end users through our pipelines. We have
acquired and are continuing to seek acquisitions of gathering facilities from
transmission companies to allow for direct connection to transmission pipelines.
Our gas gathering system is also used to carry third party natural gas to market
through purchase/resale or transport arrangements.

The principal Appalachian Basin properties are as follows:

Pikeville Area, Kentucky

The Pikeville Area includes approximately 37% of Eastern States' total net
proved reserves. Eastern States' interests in this area are concentrated in
Pike, Knott, Floyd, Breathitt, Morgan, Elliott and Carter counties, Kentucky on
approximately 352,000 gross acres, which includes the Rome area. We produce
natural gas predominantly from the Maxton, Big Lime and Berea and Devonian Shale
formations at depths ranging from 1,000 to 8,000 feet. Sales meter production
attributable to Eastern States' net interest averaged 32 MMcfe per day during
the first two quarters of 1999. Eastern States drilled 46 gross development
wells and three gross exploratory wells in this area during fiscal 1998 with 45
of the development wells and one of the exploratory wells currently producing at
a combined rate of approximately 4.0 MMcf per day. In the six month period ended
June 30, 1999, Eastern States drilled and completed 24 wells. We had 461 proved
undeveloped locations identified for drilling as of December 31, 1998.

Brenton Area, West Virginia

The Brenton Area includes approximately 30% of Eastern States' total net
proved reserves. Eastern States' interests are located mainly in Logan, Mingo,
McDowell and Wyoming counties in southern West Virginia on approximately 397,000
gross acres. We produce natural gas predominantly from the Ravencliff, Maxton,
Big Lime and Berea and Devonian Shale formations at depths ranging from 2,000 to
7,000 feet. Sales meter production attributable to Eastern States' net interest
averaged 28 MMcfe per day for the first two quarters of 1999. Eastern States
drilled and completed 57 gross wells in the area during 1998, which are
currently producing at a combined rate of approximately 6.5 MMcf per day. In the
six month period ended June 30, 1999, Eastern States drilled and completed 18
wells. We had 429 proved undeveloped locations identified for drilling as of
December 31, 1998.

Madison Area, Eastern West Virginia

The Madison Area includes approximately 17% of Eastern States' total net
proved reserves. Eastern States' interests are located in Lincoln, Kanawha,
Boone, Raleigh, Fayette, Nicholas and Clay counties in South-Central West
Virginia on approximately 374,000 gross acres. We produce natural gas
predominantly from the Maxton, Big Lime, Big Injun, Weir, Berea and Devonian
Shale formations at depths ranging from 1,700 to 6,000 feet. Sales meter
production attributable to Eastern States' net interest averaged 18 MMcfe per
day for the first two quarters of 1999. Eastern States drilled and completed 50
gross wells during 1998, all of which are currently producing at a combined rate
of approximately 4.3 MMcf per day. In the six month period ended June 30, 1999,
Eastern States drilled and completed 21 wells. We had 208 proved undeveloped
locations identified for drilling as of December 31, 1998.
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Weston Area, West Virginia

The Weston Area includes approximately 9% of Eastern States' total net
proved reserves. Eastern States' interests are located largely in Jackson,
Gilmer, Doddridge, Roane, Calhoun, Harrison and Wetzel counties in northern West
Virginia on approximately 192,000 gross acres. We produce natural gas from Upper
Devonian sandstone formations at depths ranging from 1,800 to 5,000 feet. Sales
meter production attributable to our net interest averaged 15 MMcfe per day for
the first two quarters of 1999. We drilled and completed 11 gross wells during
1998, all of which are producing at a combined rate of approximately 0.8 MMcf
per day. We had 20 proved undeveloped locations identified for drilling as of
December 31, 1998.

Noble/Cambridge Area, Ohio

The Noble/Cambridge Area includes approximately 6% of Eastern States' total
net proved reserves. Eastern States' interests are located largely in Trumbull,
Mahoning, Portage, Coshocton, Licking, Noble and Monroe counties in eastern Ohio
on approximately 87,000 gross acres. We produce natural gas predominately from
the Silurian Clinton sandstone at depths ranging from 3,500 to 6,000 feet.
Additionally, natural gas and minor amounts of oil are produced from the
Cambro-Ordovician Knox Group at depths approximating 7,000 feet, and
Mississippian and Devonian sandstones at depths of 2,000 to 3,000 feet. Sales
meter production attributable to our net interest averaged 10 MMcfe per day for
the first two quarters of 1999. Eastern States drilled and completed 11 gross
wells during 1998. Of these, nine gross wells are producing at a combined rate
of approximately 0.4 MMcfe per day. We had 40 proved undeveloped locations
identified for drilling as of December 31, 1998.

Additional Properties

Eastern States also owns additional producing properties in the Appalachian
Basin and Michigan Basin, accounting for the remaining 1% of net proved
reserves. Eastern States owns approximately 151,000 gross acres in the Illinois
Basin, approximately 5,000 gross acres in the Michigan Basin, and approximately
an additional 7,000 gross acres outside the Appalachian, Michigan and Illinois
Basins.

DEVELOPMENT ACTIVITIES

Our development activities involve technical, economic, land, and field
investigations that result in the drilling of new wells, recompleting or
deepening existing wells and optimizing production systems. We pursue
opportunities which cost effectively maximize production from our properties. A
team composed of geologists, reservoir and production engineers, landmen, and
drilling supervisors identify these opportunities through their integrated
efforts. The teams also look for opportunities to farm-in or acquire additional
acreage and wells that enhance their area's performance. Certain properties we
deem uneconomic or non-strategic are farmed-out for exploitation by third
parties.

Development drilling accounts for approximately 95% of our drilling capital
expenditures. The remaining amount is used to conduct drilling within our
exploration project areas. Our experienced geoscience staff of six professionals
coordinate our exploration efforts in the Appalachian Basin with additional
support provided by consultants. Currently, our primary exploration targets are:

- Cambrian Rome sandstones of northeastern Kentucky;

- Knox carbonates and sandstones of eastern Ohio; and

- Devonian and Silurian horizons coincident with our southern West Virginia
acreage which can be tested by extending the drill depth of our shallower
development wells in this area by 200 to 1,000 feet.

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RESERVES

We operate producing properties primarily in West Virginia, Kentucky and
Ohio in the Appalachian Basin. We also own smaller producing properties in
Virginia, Michigan and Maryland. The following table shows quantities of our net
proved natural gas and oil reserves and cash flows at December 31, 1996, 1997
and 1998. The estimated future net cash flows and the present value of estimated
future net cash flows, discounted at 10%, presented below include the value of
Section 29 tax credits and future plugging and abandonment liabilities.

AS OF DECEMBER 31,
----------------------------------
1996 1997 1998
-------- ---------- ----------
(IN THOUSANDS)

Proved developed:
Natural gas (MMcf).............................. 123,518 701,726 697,474
Oil (MBbls)..................................... 1,038 2,323 1,972
Proved undeveloped:
Natural gas (MMcf).............................. 46,404 309,567 352,240
Oil (MBbls)..................................... 87 14 32
Total proved:
Natural gas (MMcf).............................. 169,922 1,011,293 1,049,714
Oil (MBbls)..................................... 1,125 2,337 2,004
Estimated future net cash flows:
Before income tax............................... $495,748 $1,940,860 $2,157,655
After income tax................................ 340,150 1,393,163 1,524,826
Present value of estimated future net cash flows,
discounted at 10%:
Before income tax............................... $192,584 $ 680,432 $ 700,196
After income tax................................ 136,175 519,709 538,401

Ryder Scott Company, L.P. reviewed the estimates prepared by Eastern States
of Eastern States' proved reserves and the future net cash flow and present
value of cash flow attributable to proved reserves at December 31, 1996, 1997
and 1998. As prescribed by the SEC, proved reserves were estimated using natural
gas and oil prices and production and development costs as of December 31 of
each year, without escalation.

The proved natural gas and oil reserves represent estimated quantities of
natural gas, oil and natural gas liquids which geological and engineering data
demonstrate to be recoverable in future years from known reservoirs under
existing economic and operating conditions. The proved reserves are further
classified as developed and undeveloped. The reserves described below and the
related standardized measures of discounted net cash flows are estimated only
and do not purport to reflect realizable values or fair market values of Eastern
States' reserves. Reserve estimates are inherently imprecise. Substantial
revisions to existing reserve estimates occur periodically due to additional
production history from each well, current-year drilling activity and other new
geologic or reserve characteristic information that may be discovered each year.

The standardized measure of discounted future net cash flows, which are
discounted at 10%, relating to proved natural gas and oil reserves is prescribed
by SFAS Statement No. 69, "Disclosures About Oil and Gas Producing Activities."
The statement requires measurement of future net cash flows through assignment
of a monetary value to proved reserve quantities and changes therein using a
standardized formula. The amounts shown above were developed as follows:

1. An estimate was made of the quantity of proved reserves and the future
periods in which they are expected to be produced based on year-end
economic conditions.

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106

escalations are provided by contracts. The average prices used at December
31, 1996, 1997 and 1998 were $3.68, $2.57, and $2.71 per Mcf of natural
gas and $22.50, $15.00, and $9.00 per barrel of oil, respectively. For the
month of September 1999, the prevailing price of natural gas in the
Appalachian Basin for Columbia Gas Transmission, as reported by Inside
FERC, was $3.03 per MMbtu.

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

The following table provides, at December 31, 1998, the summary calculation
of the standardized measure of discounted future net cash flows attributable to
our estimated net proved reserves at that date. These estimates, which we
prepared, have been reviewed by Ryder Scott Company L.P. Dollar amounts are
presented in millions. Natural gas and oil prices used in calculating estimated
values at December 31, 1998 were $2.71 per Mcf and $9.00 per Bbl of oil. For the
month of September 1999, the published price for natural gas in the Appalachian
Basin for Columbia Gas Transmission, as reported by Inside FERC, was $3.03 per
MMBtu. The posted price for Appalachian Basin oil at September 30, 1999, was
$21.25 per Bbl.

Future gross revenues...................................... $2,902
Future production costs.................................. (549)
Future development costs................................. (195)
------
Total future costs......................................... (744)
------
Future net revenues before future income taxes............. 2,158
Discount at 10% per annum.................................. (1,458)
------
Standardized measure before future income taxes............ 700
Discounted future income taxes............................. (162)
------
Standardized measure after future income taxes............. $ 538
======

Future income taxes before discount were $633 million.

In computing this data, we used assumptions and estimates. We cannot assure
you that these assumptions and estimates will be indicative of future economic
conditions. We determined the future net revenues by using estimated quantities
of proved reserves and the periods in which they are expected to be developed
and produced based on December 31, 1998 economic conditions. The estimated
future production is priced as of December 31, 1998, except where fixed and
determinable price escalations are provided by contract. The resulting estimated
future gross revenues are reduced by estimated future costs to develop and
produce the proved reserves based on December 31, 1998 costs levels, but not for
debt service, general and administrative expenses and income taxes. Prices for
natural gas and oil are subject to substantial fluctuations as a result of
numerous factors. You should not construe the standardized measure as the
current market value of estimated natural gas and oil reserves. For additional
information concerning the discounted future net cash flows to be derived from
these reserves and the disclosure of the standardized measure information in
accordance with the provisions of Statement of Financial Accounting Standards
No. 69, you should review Note 13 to our consolidated financial statements
beginning on page AF-15 of this appendix.

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ACREAGE AND PRODUCTIVE WELLS

The following table shows the approximate amount of our developed and
undeveloped acreage at December 31, 1998. Approximately 95% of our acreage is
held by production. Acres are presented in thousands.

DEVELOPED
ACRES UNDEVELOPED ACRES TOTAL ACRES
----------- ----------------- ---------------
GROSS NET GROSS NET GROSS NET
----- --- ------ ------ ----- -----

Appalachian Basin...................... 332 298 1,073 966 1,405 1,264
Other.................................. 11 7 152 125 163 132
--- --- ----- ----- ----- -----
Total........................ 343 305 1,225 1,091 1,568 1,396
=== === ===== ===== ===== =====

The following table shows at December 31, 1998 the number of producing
wells in which we own an interest and includes approximately 1,500 wells
associated with Section 29 tax credit monetization:

TOTAL PRODUCING WELLS
----------------------
GROSS NET
----- ---

Natural Gas...................................... 5,732 5,388
Oil.............................................. 4 4
----- -----
Total.................................. 5,736 5,392
===== =====

DRILLING ACTIVITIES

During the periods indicated, we drilled or participated in the drilling of
the following exploratory and development wells.

YEAR ENDED DECEMBER 31, SIX MONTHS ENDED
-------------------------------------------- JUNE 30,
1996 1997 1998 1999
------------ ------------- ------------- -----------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- ---

Exploratory wells:
Productive.................... 5.0 3.0 4.0 2.3 3.0 2.4 2.0 2.0
Nonproductive................. 0 0 4.0 2.2 4.0 3.5 1.0 0.5
Development wells:
Productive.................... 73.0 71.5 116.0 113.0 171.0 168.1 59.0 58.5
Nonproductive................. 1.0 1.0 1.0 1.0 1.0 0.5 0 0
----- ---- ----- ----- ----- ----- ---- ----
Total................. 79.0 75.5 125.0 118.5 179.0 174.5 62.0 61.0

As of July 31, 1999, we were drilling nine wells in the Appalachian Basin.

NET PRODUCTION, UNIT PRICES AND COSTS

Our lease operating expenses, including both well tending and gathering and
compression costs, averaged $0.41 per Mcfe for the year ended December 31, 1998
and $0.40 per Mcfe for the six months ended June 30, 1999. Over the past three
fiscal years we have reduced our drilling cost per well in the region by
approximately 10%.

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The following table provides information with respect to our net production
and average unit prices and costs for the periods indicated. Since natural gas
represents over 98% of our production, this information is presented in Bcfe or
Mcfe:

SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------ ----------------
1996 1997 1998 1998 1999
------ ------ ------ ----- -----

Production (wellhead):
Gas Equivalents (Bcfe)..................... 6.6 24.7 38.7 19.5 20.0
Average sales price (hedged):
Gas Equivalents ($/Mcfe)................... $2.76 $2.62 $2.46 $2.57 $2.66
Average sales price (unhedged):
Gas Equivalents ($/Mcfe)................... $2.94 $2.80 $2.28 $2.41 $2.26
Average lease operating expenses ($/Mcfe).... $0.40 $0.55 $0.41 $0.41 $0.40

MARKETING AND CONTRACTS

General. The close proximity of Appalachian production to a substantial
number of industrial and commercial end users in the northeastern United States
has traditionally provided producers a premium to Henry Hub, Louisiana prices.
This premium has averaged $0.26 per MMBtu over the past three calendar years.
For the period 1991 through 1998, wellhead natural gas prices in the Appalachian
Basin have averaged on an annual basis $0.25 per MMbtu more than Henry Hub and
NYMEX wellhead natural gas prices. During these eight years, the Appalachian
Basin annual premium has ranged from $0.14 per MMbtu to $0.47 per MMbtu over
NYMEX prices. In addition to its location premium, our Appalachian Basin gas
production has a higher Btu, or energy, content than natural gas produced in
many other areas of the United States, which also results in premium pricing
since index prices are typically based on an energy content of 1,000 Btu per
cubic foot.

We balance our spot and term natural gas sales to end-users and local
distribution companies and utilize multiple pricing structures. Eastern States
currently has two significant market-based contracts, one with affiliates of CNG
Transmission Corp. and the other with its own affiliate, Statoil Energy
Services, Inc. Each of these contracts expires in October 2000. In 1998, over
80% of the natural gas produced by Eastern States was sold under these
contracts, with 59% sold to Statoil Energy Services and 23% sold to CNG. During
the six months ended June 30, 1999, 60% of our natural gas was sold to Statoil
Energy Services and 30% to CNG. Eastern States believes that it will be able to
sell its natural gas under comparable terms should these contracts not be
renewed. Substantially all of our remaining natural gas is sold pursuant to
multi-month and/or one-year term agreements.

CNG. Under the CNG contract, affiliates of CNG purchase natural gas from
Eastern States based on the terms contained in confirmations which the parties
enter into from time to time. The CNG confirmations set forth the following:

- quantity;

- price;

- delivery point; and

- effective period of the confirmation.

The price under the CNG contracts has historically been based on the
published price of Inside FERC-Appalachian Basin for CNG, plus a premium based
on the higher Btu content, less applicable gathering, compression and processing
fees. The price for the natural gas is inclusive of all taxes levied on
production or transportation of the natural gas up to the delivery point.
Payment from the CNG affiliates are due by the 55th day following delivery.

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Each CNG confirmation sets forth the period of time that the terms of the
confirmation are effective. The effective period of a confirmation with the CNG
affiliates has typically been for 12 months.

Statoil Energy Services. The contract with Statoil Energy Services is also
based on the terms contained in confirmations similar to the CNG confirmations
which the parties enter into from time to time.

The price under the Statoil Energy Services contract has historically been
based on the published price of Inside FERC -- Appalachian Basin for Columbia
Gas Transmission Corp. for natural gas delivered into Columbia Gas
Transmission's pipeline system, plus a premium based on the higher Btu content,
less applicable gathering, compression and processing fees. Eastern States is
responsible for all taxes attributable to the natural gas before the delivery
point. Statoil Energy Services is responsible for all taxes attributable to the
natural gas after the delivery point. Payment from Statoil Energy Services is
due by the 55th day following delivery.

Each confirmation with Statoil Energy Services sets forth the quantity of
natural gas to be delivered by Eastern States to the delivery point. Title and
risk of loss pass to Statoil Energy Services at the delivery point.

Each confirmation also sets forth the period of time that the terms of the
confirmation are effective. The effective period of a confirmation with Statoil
Energy Services has historically been for 12 months.

Third Party Services. Our 3,500 miles of Appalachian Basin gathering lines
provide us with the opportunity to purchase or transport third party gas
supplies for delivery into major interstate pipelines. We generally make these
purchases along our gathering pipeline systems, but also make purchases
off-system. Frequently, we market gas for joint venture partners. Our gathering
systems have enabled us to generate gross margins approximating $0.25 per MMBtu
over the past three years on third party volumes. Providing gathering services
to third parties allows Eastern States to obtain reimbursement for compressor
fuel and line loss amounts.

Domestic Customers. We also serve domestic customers at rates established
by state regulatory authorities. Revenues from these sales represent less than
1% of total revenues.

Hedging and Risk Management. We utilize forward sales of our production in
order to lock-in prices that we determine to be attractive and to achieve a
certain return on investment. In fiscal years 1996, 1997 and 1998, we hedged
approximately 70%, 70% and 60%, respectively, of our natural gas production.
This strategy has been successful in achieving our income goals. However, it has
limited our potential gains from increases in market prices. At June 30, 1999,
we had the following open natural gas hedges:

MMBTU PER DAY DATE AVERAGE NYMEX PRICE PER MCF
- ------------- ---- ---------------------------

105 July 1999 to December 1999 $ 2.24
80 Year 2000 2.36
20 Year 2001 2.36
10 Years 2002 to 2008 2.35 to 2.45
30 April to October in years 2000 to 2003 2.10 to 2.30

In addition to our natural gas hedges, we have hedged a small amount of our
oil production and Appalachian Basin premium. We plan to continue to hedge our
natural gas production, which will exclude the production attributable to the
trust in the future in order to reduce our exposure to significant declines in
the market price to ensure minimum levels of cash flow from our sales of oil and
gas. At the time we divest of any of our oil and gas properties, including the
sale of oil and gas properties to the trust as

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contemplated herein, we would close out our hedging positions and include the
gain or loss, resulting from the hedges as a part of the property sale for
financial reporting purposes. At no time does the Company enter into speculative
positions.

SECTION 29 TAX CREDITS

The Crude Oil Windfall Profits Tax Act of 1980 amended the Internal Revenue
Code to provide an incentive for natural gas production from unconventional
sources such as the Devonian Shale and tight sandstone formations of the
Appalachian Basin. Under Section 29 of the Internal Revenue Code, an owner of an
economic interest in natural gas production can qualify for income tax credits
on qualified production that is produced through December 31, 2002.

As part of our acquisition of Blazer Energy, we acquired Blazer Energy's
working interests in approximately 1,450 gross wells that qualified for Section
29 tax credits under the Internal Revenue Code. In December 1997, we transferred
substantially all the wells that qualified for Section 29 tax credits to our
subsidiary Eastern Seven, LLC. Eastern Seven then entered into an agreement
under which it monetized the value of its future Section 29 tax credits. Under
the terms of the agreement, Eastern Seven transferred title to these wells to a
trust, but retained a production payment and a note that entitle Eastern Seven
to all of the cash flow from the properties until approximately 95% of the
pre-tax net present value of the presently projected future production from the
properties has been received, which is expected to occur in the year 2018. In
addition to the note and production payment, Eastern Seven received a fixed cash
payment of $7.9 million at closing and will receive quarterly payments through
2002 equal to a specified percentage of the Section 29 tax credits generated
from the properties. These quarterly payments are expected to decline from
approximately $2.3 million per quarter in 1998 to approximately $1.9 million per
quarter in 2002.

In April 1999, we conveyed approximately 100 wells qualifying for Section
29 tax credits to Eastern Seven, LLC. Eastern Seven then entered into a
monetization agreement under similar terms and received a fixed cash payment of
$0.5 million at closing and will receive quarterly payments through 2002 equal
to a specified percentage of the Section 29 tax credits generated from the
properties. These quarterly payments are expected to decline from approximately
$117,000 per quarter in 1999 to approximately $107,000 per quarter in 2002.

Based on current law, Devonian Shale and tight sand tax credits will be
available until December 31, 2002. Eastern Seven has the option to repurchase
the properties after December 31, 2002 at the fair market value of the
properties at the time of repurchase less the value of the outstanding note and
production payment. Eastern States also entered into a management services
agreement with the trust pursuant to which Eastern States manages and operates
the properties on behalf of the trust.

RELATIONSHIP WITH STATOIL ENERGY

In August 1999, Statoil Energy Holdings agreed to combine and extend to
December 31, 2001 the final repayment dates of various notes payable to Statoil
Energy Holdings aggregating approximately $505 million of indebtedness at
December 31, 1998. This note has an 8% annual rate of interest, payable
semi-annually on January 1 and July 1 each year. At September 30, 1999, the
total amount of outstanding indebtedness under the note payable to Statoil
Energy Holdings was approximately $505 million and our intercompany indebtedness
owed to affiliates of Statoil Energy was approximately $51 million.

Since 1997, Eastern States, along with Statoil Energy and Statoil Energy
Holdings, has participated in a tax allocation agreement whereby all required
federal income tax returns for 1997 and thereafter are filed on a consolidated
basis. For each tax period, each subsidiary computes its separate tax liability
or receivable on a separate company basis. Any subsidiary tax liability is paid
to Statoil Energy by the subsidiary or, if there is a subsidiary tax benefit,
Statoil Energy will reimburse the subsidiary.

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In 1997, Eastern States sold the Gulf of Mexico properties acquired in the
Blazer acquisition in July 1997 to Eastern States' affiliate Statoil Exploration
U.S., Inc., an indirect wholly owned subsidiary of The Statoil Group, for
approximately $82 million.

Substantially all full-time employees of Eastern States participate in a
profit-sharing plan sponsored by Statoil Energy that includes an employee
savings feature under Section 401(k) of the Internal Revenue Code. Participants
in the plan may elect to defer up to 15% of their total compensation through
contributions to the plan and Statoil Energy matches 50% of employee
contributions up to 6% of an employee's total compensation. Statoil Energy's
matching vests within five years.

As described in more detail under the heading "Eastern States Oil & Gas,
Inc." on page A-1, The Statoil Group has decided to sell its equity ownership in
Statoil Energy, including Eastern States.

COMPETITION

Competition in our primary producing areas is intense. We actively compete,
in some cases against companies with substantially larger financial and other
resources, in the:

- acquisition of producing properties and natural gas and oil leases;

- marketing of natural gas and oil; and

- obtaining goods, services and labor.

There are numerous exploration and production companies in the Appalachian
Basin that compete directly with Eastern States. Only two of these have similar
daily volume production, leasehold acreage and proved natural gas reserves as
compared to Eastern States. These two companies are owned by U.S. natural gas
utilities who have regulated local gas distribution and interstate gas
transmission subsidiaries, in addition to their exploration and production
subsidiary. Both of these companies have active drilling programs and directly
compete with Eastern States. We have substantial relationships with both of
these companies to gather and transmit our natural gas.

To the extent that our gas supply, gathering systems, organization or
development budget are smaller than those of some of our competitors, we may be
disadvantaged in our competitive activities. We believe that our competitive gas
marketing position is based on location, price, contract terms, quality of
service and reliable delivery record. We believe that our extensive acreage
position, substantial ongoing development program and existing gas gathering
systems give us a competitive advantage over other producers in the Appalachian
Basin that do not have similar systems or facilities in place.

TITLE TO PROPERTIES

As is customary in the natural gas and oil industry, we make only a cursory
review of title to farm-out acreage and to undeveloped natural gas and oil
leases upon execution of the contracts. Prior to the commencement of drilling
operations, a thorough title examination may be conducted and curative work may
be performed with respect to significant defects. To the extent title opinions
or other investigations reflect title defects, we, rather than the seller of the
undeveloped property, are typically responsible to cure any such title defects
at our expense. If we were unable to remedy or cure any title defect of a nature
such that it would not be prudent to commence drilling operations on the
property, we could suffer a loss of our entire investment in the property. We
believe that we have satisfactory title to the properties in accordance with
standards generally accepted in the oil and gas industry. Our natural gas and
oil properties are subject to customary royalty interests, liens for current
taxes and other burdens that we believe do not materially interfere with the use
of or affect the value of such properties.

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GOVERNMENT REGULATION

Regulation of Natural Gas and Oil Exploration and Production

Our exploration and production operations are subject to various types of
regulation at the federal, state and local levels. This regulation includes:

- requiring permits for the drilling of wells;

- maintaining bonding requirements in order to drill or operate wells; and

- regulating the location of wells, the method of drilling and casing
wells, the surface use and restoration of properties upon which wells are
drilled and the plugging and abandonment of wells.

Our operations are also subject to various conservation laws and
regulations. These laws and regulations may include:

- the density or spacing of wells that may be drilled;

- the unitization or pooling of oil and gas properties; and

- the regulation of the maximum rate of production from natural gas and oil
wells.

The effect of these regulations may limit the amounts of natural gas and
oil that we can produce from our wells, and limit the number of wells or the
locations at which we can drill. Legislation affecting the oil and gas industry
also is under constant review for amendment or expansion. In addition, numerous
departments and agencies, both federal and state, are authorized by statute to
issue rules and regulations binding on the natural gas and oil industry and its
individual members, some of which carry substantial penalties for failure to
comply. The regulatory burden on the natural gas and oil industry increases our
cost of doing business and, as a result, affects our profitability. Because laws
and regulations are frequently expanded, amended and reinterpreted, we are
unable to predict the future cost or impact of complying with any laws and
regulations.

Federal Regulation of Gas.

Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission
regulates the interstate transportation and the sale in interstate commerce for
resale of natural gas. The FERC's jurisdiction over interstate natural gas sales
was substantially modified by the Natural Gas Policy Act, under which the FERC
continued to regulate the maximum selling prices of specified categories of gas
sold in "first sales" in interstate and intrastate commerce. Effective January
1, 1993, however, the Natural Gas Wellhead Decontrol Act deregulated natural gas
prices for all "first sales" of natural gas. Because "first sales" include
typical wellhead sales by producers, all natural gas produced from Eastern
States' natural gas properties is being sold at market prices, subject to the
terms of any private contracts which may be in effect. The FERC's jurisdiction
over natural gas transportation was not affected by the Decontrol Act.

Eastern States' sales of natural gas are affected by intrastate and
interstate gas transportation regulation. Beginning in 1985, the FERC adopted
regulatory changes that have significantly altered the transportation and
marketing of natural gas. These changes were intended by the FERC to foster
competition by, among other things, transforming the role of interstate pipeline
companies from wholesale marketers of gas to the primary role of gas
transporters. All gas marketing by the pipelines was required to be divested to
a marketing affiliate, which operates separately from the transporter and in
direct competition with all other merchants. As a result of the various omnibus
rulemaking proceedings in the late 1980s and the individual pipeline
restructuring proceedings of the early to mid-1990s, the interstate pipelines
are now required to provide open and nondiscriminatory transportation and
transportation-related services to all producers, gas marketing companies, local
distribution companies, industrial end users and other customers seeking
service. Through similar orders affecting intrastate pipelines that provide
similar interstate services, the FERC expanded the impact of open access
regulations to intrastate commerce.

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113

More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing, including:

- the large-scale divestiture of interstate pipeline-owned gas gathering
facilities to affiliated or non-affiliated companies;

- further development of rules governing the relationship of the pipelines
with their marketing affiliates;

- the publication of standards relating to the use of electronic bulletin
boards and electronic data exchange by the pipelines to make available
transportation information on a timely basis and to enable transactions
to occur on a purely electronic basis;

- further review of the role of the secondary market for released pipeline
capacity and its relationship to open access service in the primary
market; and

- development of policy and promulgation of orders pertaining to its
authorization of market-based rates, rather than traditional
cost-of-service based rates, for transportation or transportation-related
services upon the pipeline's demonstration of lack of market control in
the relevant service market. We cannot predict what effect the FERC's
other activities will have on the access to markets, the fostering of
competition and the cost of doing business.

As a result of these changes, sellers and buyers of gas have gained direct
access to the particular pipeline services they need and are better able to
conduct business with a larger number of counterparties. Eastern States believes
these changes generally have improved the access to markets for its natural gas
while, at the same time, substantially increasing competition in the natural gas
marketplace. We cannot predict what new or different regulations the FERC and
other regulatory agencies may adopt, or what effect subsequent regulations may
have on production and marketing of gas from our properties.

In the past, Congress has been very active in the area of gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation and the promotion of competition in the gas industry. Thus, in
addition to "first sale" deregulation, Congress also repealed incremental
pricing requirements and gas use restraints previously applicable. There are
other legislative proposals pending in the Federal and state legislatures which,
if enacted, would significantly affect the petroleum industry. At the present
time, we cannot predict what proposals, if any, Congress or the various state
legislatures might actually enact and what effect, if any, these proposals might
have on our production and marketing of gas. Similarly, and despite the trend
toward federal deregulation of the natural gas industry, we cannot predict
whether or to what extent that trend will continue, or what the ultimate effect
will be on our production and marketing of gas.

Federal Regulation of Petroleum.

Eastern States' sales of oil are not regulated and are at market based
prices. The price received from the sale of these products is affected by the
cost of transporting the products to market. Much of that transportation is
through interstate common carrier pipelines. Effective as of January 1, 1995,
the FERC implemented regulations generally grandfathering all previously
approved interstate transportation rates and establishing an indexing system for
those rates by which adjustments are made annually based on the rate of
inflation, subject to certain conditions and limitations. These regulations may
tend to increase the cost of transporting oil and natural gas liquids by
interstate pipeline, although the annual adjustments may result in decreased
rates in a given year. These regulations have generally been approved on
judicial review. Every five years, the FERC will examine the relationship
between the annual change in the applicable index and the actual cost changes
experienced by the oil pipeline industry. The first such review is scheduled for
the year 2000. We are not able to predict with certainty what effect, if any
these relatively new federal regulations nor the periodic review of the index by
FERC will have on it.

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Safety and Health Regulation

Our gathering operations are subject to occupational safety, health and
operational regulations relating to the design, installation, testing,
construction, operation, replacement and management of facilities. Pipeline
safety issues have recently been the subject of increasing focus in various
political and administrative arenas at both the state and federal levels. We
believe our operations, to the extent they may be subject to current natural gas
pipeline safety or other health and safety requirements, comply in all material
respects with these requirements. We cannot predict what effect, if any, the
adoption of additional pipeline safety or other safety and health legislation
might have on our operations, but the industry could be required to incur
additional capital expenditures and increased costs depending upon future
legislative and regulatory changes.

ENVIRONMENTAL MATTERS

Our operations are subject to federal, state and local laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. Numerous governmental agencies issue rules and
regulations to implement and enforce these laws, which may be costly to comply
with and carry substantial penalties for failure to comply. These laws and
regulations may:

- require the acquisition of one or more permits before drilling commences;

- restrict the types, quantities and concentration of various substances
that can be released into the environment in connection with drilling and
production activities;

- limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas;

- require measures to prevent the release of contaminants into the
environment from former operations, such as the remediation of former or
current well sites, including pit closure and plugging abandoned wells;
and

- impose substantial liabilities and penalties if any contaminants are
released into the environment as a result of our operations.

In addition, these laws, rules and regulations may restrict the rate of oil
and natural gas production below the rate that would otherwise exist or may
require that certain wells be shut-in. The regulatory burden on the natural gas
and oil industry increases the cost of doing business and consequently affects
our profitability and the profitability of others in the industry. Our
expenditures in the near future for regulatory and environmental compliance are
not expected to be material in relation to our total capital expenditure
program; however, we cannot predict the ultimate cost of compliance because
costs are highly dependent on the facts and circumstances of a particular
situation and environmental laws and regulations frequently change. Although we
believe that our operations and facilities are in compliance in all material
respects with current applicable environmental regulations, risks of substantial
costs and liabilities are inherent in gas and oil operations, and we cannot
assure you that we will not incur significant costs and liabilities in the
future. A change in current environmental laws and regulations could have an
adverse effect on our financial condition and results of operations.

CERCLA

The Comprehensive Environmental Response, Compensation and Liability Act,
which is commonly known as CERCLA and also as the Superfund law, imposes
liability, without regard to fault or the legality of the original conduct, on
persons who are considered to be responsible for the release of a hazardous
substance into the environment. While most oil and gas exploration and
production wastes are not considered hazardous substances, there may be some
materials present at an oil and gas well or used in oil and gas exploration and
production operations that are considered hazardous substances. Persons who may
be liable under CERCLA, usually referred to as potentially responsible parties,
include the current or former owner or operator of the disposal site or sites
where the release occurred and companies that

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disposed or arranged for the disposal of the hazardous substances found at a
site and companies that transported the hazardous substance for disposal. Under
CERCLA, potentially responsible parties may be subject to joint and several
liability for the costs of cleaning up hazardous substances that have been
released into the environment, for damages to natural resources and for the
costs of some health studies. In addition, where a release of a hazardous
substance has occurred, it is not uncommon for neighboring landowners and other
third parties to file lawsuits claiming for personal injury and property damage
allegedly caused by hazardous substances or other pollutants released into the
environment.

Stricter standards in environmental legislation may be imposed on the oil
and gas industry in the future. For instance, from time to time legislation has
been proposed in Congress that would reclassify certain oil and natural gas
exploration and production wastes as "hazardous wastes" subject to more
stringent handling, disposal and cleanup requirements. If such legislation were
enacted, it could have a significant impact on our operating costs, as well as
the oil and gas industry in general. Furthermore, although petroleum, including
oil and natural gas, is exempt from CERCLA, at least two courts have ruled that
certain wastes associated with the production of oil may be classified as
hazardous substances under CERCLA. State initiatives to regulate further the
disposal of oil and natural gas wastes are pending in several states, and these
initiatives could have a similar impact on us. Although future changes in
federal and state law related to discharge into navigable waters or state waters
could have a significant impact on our operating costs, the entire industry will
experience a similar impact and we believe that the increased costs will not
have a material adverse impact on our financial conditions and operations.

Solid and Hazardous Waste

The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976, which is commonly known as RCRA,
regulates the generation, transportation, storage, treatment and disposal of
hazardous wastes, and can require cleanup of hazardous waste disposal sites.
RCRA currently excludes drilling fluids, produced waters and other wastes
associated with the exploration, development or production of natural gas and
oil from the definition of hazardous waste. Disposal of non-hazardous oil and
gas exploration, development and production wastes may be regulated by state
law. In addition, we occasionally handle material that may be classified as
hazardous waste under RCRA. RCRA and state laws impose certain operational
requirements upon the storage, handling and disposal of these materials.

LITIGATION

Various legal actions that have arisen in the ordinary course of business
are pending with respect to Eastern States and its affiliates. We do not expect
any of these proceedings to have a material adverse impact on our results of
operations or financial position.

OPERATING HAZARDS AND UNINSURED RISKS

Our operations are subject to hazards and risks inherent in drilling for
and production and transportation of oil and natural gas, such as:

- fires;

- natural disasters;

- explosions;

- encountering formations with abnormal pressures;

- blowouts;

- cratering;

- pipeline ruptures; and

- spills,

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any of which can result in loss of hydrocarbons, environmental pollution,
personal injury claims, and other damage to our properties and properties of
others. As protection against operating hazards, we maintain insurance coverage
against some, but not all, potential losses. We believe that our insurance is
adequate and customary for companies of a similar size engaged in operations
similar to ours, but losses could occur for uninsurable or uninsured risks or in
amounts in excess of existing insurance coverage. The occurrence of an event
that is not fully covered by insurance could have an adverse impact on our
financial condition and results of operations.

EMPLOYEES

As of June 30, 1999, we had 276 employees in eight offices. We believe that
our relations with our employees are satisfactory. We have not entered into any
collective bargaining agreements with any of our employees.

OFFICES

Statoil Energy maintains its corporate headquarters in Alexandria, Virginia
where it leases approximately 110,000 square feet of office space. Eastern
States maintains its corporate headquarters in the same building and subleases
approximately 17% or 19,000 square feet of the office space from Statoil Energy.
We also have a regional office in Charleston, West Virginia, with field offices
in Weston, West Virginia; Madison, West Virginia; Brenton, West Virginia;
Pikeville, Kentucky; Ravenna, Ohio; and Cambridge, Ohio.

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SELECTED FINANCIAL INFORMATION

The following table shows selected historical financial information for
Eastern States Oil & Gas, Inc. and reflects the acquisition of the domestic
natural gas and oil producing properties of Blazer Energy Corp. in July of 1997.
The selected historical financial information as of and for the three years
ended December 31, 1998 have been derived from our audited consolidated
financial statements. The summary historical financial information for the two
years ended December 31, 1995 and for the six months ended June 30, 1998 and
1999 has been derived from our unaudited financial statements. The results for
the six months ended June 30, 1999 are not necessarily indicative of the results
that may be expected for any other period or for the full year. The following
information should be read in conjunction with our financial statements and the
notes thereto and "Management's Discussion and Analysis of Financial Condition
and Results of Operations" contained elsewhere in this appendix.

YEAR ENDED SIX MONTHS
DECEMBER 31, YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------ -------------------------------- --------------------
1994 1995 1996 1997 1998 1998 1999
------- ------- -------- -------- -------- -------- --------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS)

INCOME STATEMENT DATA:
Total revenues............ $1,772.. $ 4,852 $ 18,247 $ 65,368 $104,670 $ 54,677 $ 57,723
------- ------- -------- -------- -------- -------- --------
Operating expenses........ 623 1,244 2,655 13,454 15,950 7,927 8,043
Depreciation, depletion
and amortization........ 550 1,429 4,783 19,073 31,517 16,520 16,129
General and administrative
expenses................ -- -- 1,630 3,254 5,462 2,249 2,868
------- ------- -------- -------- -------- -------- --------
Total costs and
expenses................ 1,173 2,673 9,068 35,781 52,929 26,696 27,040
------- ------- -------- -------- -------- -------- --------
Operating income.......... 599.... 2,179 9,179 29,587 51,741 27,981 30,683
Interest expense, net of
interest income......... 518 2,061 4,338 21,608 38,952 19,513 21,265
------- ------- -------- -------- -------- -------- --------
Income before income
taxes................... 81 118 4,841 7,979 12,789 8,468 9,418
Income tax expense
(benefit)............... -- -- 956 (1,171) 4,443 3,112 3,372
------- ------- -------- -------- -------- -------- --------
Net income................ $ 81 $ 118 $ 3,885 $ 9,150 $ 8,346 $ 5,356 $ 6,046
======= ======= ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Net cash provided by (used
for)
Operating activities.... (177) 40,341 10,301 12,244 40,511 22,081 24,818
Investing activities.... (19,173) (28,641) (56,571) (514,809) (56,551) (506) (21,061)
Financing activities.... 19,500 (12,499) 46,270 502,565 16,040 (21,575) (3,757)
Capital expenditures...... 19,173 28,641 56,789 597,007 82,525 25,045 21,990
BALANCE SHEET DATA (AT END
OF PERIOD):
Working capital........... 638 (1,979) (2,133) 10,057 13,215 12,709 13,412
Oil and gas properties,
net..................... 18,336 40,683 96,770 589,889 615,611 573,857 620,873
Total assets.............. 19,945 45,564 100,469 626,339 658,333 602,472 651,867
Total long-term debt...... 19,500 41,366 69,633 503,588 505,488 505,488 505,488
Stockholder's equity...... 81 1,700 5,585 64,735 73,081 70,090 79,127

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SUMMARY RESERVE AND OPERATING DATA

The following shows summary reserve and operating information as of and for
the periods indicated. Calculation of the standardized measure is made using a
10% discount rate in accordance with the rules and regulations of the SEC and
includes the value of Section 29 tax credits and future plugging and abandonment
liabilities. The reserve to production ratio presented below represents year-end
reserves divided by that year's production. For additional information regarding
our proved reserves as reviewed by Ryder Scott Company, L.P. and other
information regarding our gas and oil reserves, see "Business and
Properties -- Reserves" and Note 13 to our consolidated financial statements
presented on page AF-15 of this appendix.

YEAR ENDED DECEMBER 31,
--------------------------------------------------
1994 1995 1996 1997 1998
------- ------- -------- -------- --------

NET PROVED RESERVES (AT END OF PERIOD):
Natural gas (Bcf)......................... 38 82 170 990 1,050
Oil (MMBbls).............................. -- -- 1 2 2
Total proved reserves (Bcfe).............. 38 83 177 1,025 1,062
Percent proved developed reserves......... 68% 75% 73% 69% 67%
Standardized measure before future income
taxes (in thousands).................... $27,539 $66,170 $192,584 $680,432 $700,196
Standardized measure after future income
taxes (in thousands).................... $21,145 $52,071 $136,175 $519,709 $538,401
Reserve to production ratio............... 51 40 27 45 29
AVERAGE DAILY PRODUCTION:
Natural gas (MMcf per day)................ 2 6 17 61 98
Oil (MBbls per day)....................... -- -- -- -- --
Total production (MMcfe per day).......... 2 6 18 63 100
YEAR END COMMODITY PRICES:
Natural gas ($/Mcf)....................... $ 2.55 $ 3.06 $ 3.68 $ 2.57 $ 2.71
Oil ($/Bbl)............................... $ 15.50 $ 16.50 $ 22.50 $ 15.00 $ 9.00

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following information should be read in conjunction with the
information contained in our financial statements and the notes thereto included
elsewhere in this appendix.

OVERVIEW

As an independent energy producer, we are engaged in the exploration for
and the development, production, gathering, transportation, acquisition and
marketing of natural gas and oil primarily in the Appalachian Basin. We are
principally a natural gas producer, with natural gas making up over 98% of our
net revenue for the year ended December 31, 1998 and the six months ended June
30, 1999. Our average natural gas production increased from 2 MMcfe per day at
year-end 1994 to 104 MMcfe per day in the six-month period ended June 30, 1999.

Our results of operations are determined in large part by the differences
between the prices received for the natural gas produced and the cost to find,
develop, produce, transport and market such natural gas. Changes in sales price
received for our production directly affect our determination to proceed with
the development of natural gas and our quantity of proved reserves. In addition
to changes in supply and demand, natural gas and oil prices are influenced by
seasonal factors, natural gas transportation and storage infrastructure,
imports, political and regulatory developments and competition from other
sources of energy and have been volatile over the last three years. Final prices
for prompt month natural gas contracts traded on the NYMEX for delivery of gas
at Henry Hub, Louisiana, have ranged from a low of approximately $1.67 per MMBtu
to a high of approximately $4 per MMBtu during the period from January 1, 1996
to December 31, 1998. It is management's view that general price inflation did
not materially impact reported net sales, revenues or income for continuing
operations for the three years ended December 31, 1998. Our production volume
growth in recent years has occurred through exploration and development of our
core holdings, as well as from producing property acquisitions, the most
significant of which was the acquisition of Blazer Energy in July 1997 for $567
million.

Based upon the results of operations for the year ended December 31, 1998,
and excluding the effect of our hedging program, a change of $0.10 per Mcf in
the average price of natural gas throughout such period would result in
corresponding changes in operating and net income of $3.8 million and $2.5
million, respectively. We intend to continue to utilize hedging to limit our
exposure to significant declines in market prices and to ensure minimum levels
of cash flow from our sales of natural gas and oil. See "Business and
Properties -- Marketing and Contracts -- Risk Management."

We follow the full cost method of accounting for our natural gas and oil
exploration and production activities. Under this method, we capitalize all
productive and non-productive costs associated with acquisition, exploration and
development activities. The capitalized costs of producing natural gas and oil
properties are depreciated, depleted and amortized by the units-of-production
method based on estimated proved reserves.

We periodically review our proved properties in accordance with Rule
4-10(c)(4) of Regulation S-X to determine whether the unamortized capitalized
costs of such properties less related deferred income taxes, as reflected in our
accounting records, exceeds the estimated discounted future net revenues
attributable to the proved properties, as adjusted.

We periodically review our other properties to determine whether the
carrying value of such properties as reflected in our accounting records exceeds
the estimated undiscounted future net revenues attributable to such properties.
Based on this review and the continuing evaluation of development plans,
economics and other factors, if appropriate, we would record impairments
(additional depletion and depreciation) pursuant to Statement of Financial
Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed of," to the extent
that the net book values of its other properties exceed the expected discounted
future net revenues. Such impairments would constitute a charge to earnings
which does not impact our cash flow from operating activities. However, such
potential write-downs impact the amount of stockholders' equity and, therefore,

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the ratio of debt to equity. We have not incurred impairment charges for the
periods presented. No assurance can be given that we will not experience
impairments in the future.

RESULTS OF OPERATIONS

Operating results for Eastern States are presented in the tables and
analyses that follow.

OPERATING RESULTS

SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
---------------------------- -----------------
1996 1997 1998 1998 1999
------- ------- -------- ------- -------
(IN THOUSANDS)

Salesmeter volumes (Bcfe)........... 6.5 23.0 36.5 18.4 18.8
Average realized salesmeter oil &
gas price (hedged) ($ per Mcfe)... 2.81 2.81 2.61 2.72 2.83
Oil & gas revenue (hedged).......... $18,247 $64,604 $ 95,315 $50,034 $53,149
Tax credit monetization............. -- 764 9,355 4,643 4,574
Total revenues...................... $18,247 $65,368 $104,670 $54,677 $57,723
Operating expenses.................. 2,655 13,454 15,950 7,927 8,043
Depreciation, depletion and
amortization...................... 4,783 19,073 31,517 16,520 16,129
General and administrative
expenses.......................... 1,630 3,254 5,462 2,249 2,868
Operating income.................... $ 9,179 $29,587 $ 51,741 $27,981 $30,683

SIX MONTHS ENDED JUNE 30, 1998 COMPARED TO SIX MONTHS ENDED JUNE 30, 1999

Revenue for the six months ended June 30, 1999 was $57.7 million, or 5.5%
higher than the six months ended June 30, 1998. Natural gas and oil revenues
increased 6.2% to $53.1 million for the six months ended June 30, 1998, compared
to $50.0 million for the six months ended June 30, 1999. This increase was
principally due to higher produced volumes, which increased from 101.7 MMcfe per
day in 1998 to 103.8 MMcfe per day in 1999, and higher average realized selling
prices, which increased from $2.72 per Mcfe in 1998 to $2.83 per Mcfe in 1999.

Operating expenses increased 1.3% from $7.9 million for the six months
ended June 30, 1998 to $8.0 million for the six months ended June 30, 1999. This
increase was due principally to volume increases as operating expenses per Mcfe
for each period approximated $0.43 per Mcfe.

Depreciation, depletion and amortization decreased by 2.4% from $16.5
million for the six months ended June 30, 1998 to $16.1 million for the six
months ended June 30, 1999. This favorable change in the depreciation, depletion
and amortization rate per Mcfe, from $0.90 to $0.86, reflects favorable drilling
results for the period July 1998 to June 1999, which resulted in increased
proved developed and proved undeveloped gas reserves. The 4.5% decrease in the
depreciation, depletion and amortization rate was partially offset by additional
costs resulting from a 2.1% increase in volumes.

Selling, general and administrative expenses increased 27% from $2.2
million for the six months ended June 30, 1998 to $2.8 million for the six
months ended June 30, 1999. This increase was attributable to increased
investments in information technology.

Interest expense increased from $19.5 million for the six months ended June
30, 1998 to $21.3 million for the six months ended June 30, 1999. This increase
is directly attributable to higher spending in support of development efforts.
Eastern States has a credit facility with Statoil Energy Holdings which provides
for borrowings at a 8% annual fixed interest rate. Outstanding borrowings at
December 31, 1998 were $505.5 million.

Pre-tax income was $9.4 million and $8.5 million for the six months ended
June 30, 1999 and 1998, respectively. The effective income tax rate approximated
36% in each period.

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FISCAL YEAR ENDED DECEMBER 31, 1998 COMPARED TO FISCAL YEAR ENDED DECEMBER 31,
1997

Revenues for 1998 were $104.7 million, or 60% higher than 1997 revenues of
$65.4 million. The increase in revenues is attributable to the Blazer Energy
acquisition as of July 1, 1997, which increased daily production from 22.6
MMcfe/day to 100.0 MMcfe/day. Production increased 61% from approximately 23
Bcfe in 1997, based on one-half year of Blazer Energy volumes, to approximately
37 Bcfe in 1998. Section 29 tax credits monetized in December 1997, provided
$0.8 million and $9.4 million in additional revenues in 1997 and 1998,
respectively. The production increase was partially offset by a 7% decrease in
the realized gas price from $2.81 per Mcfe in 1997 to $2.61 per Mcfe in 1998.

Operating expenses increased nearly 18% from $13.5 million in 1997 to $15.9
million in 1998. This increase is principally due to a full year of Blazer
Energy operations in 1998. The Company successfully assimilated Blazer Energy
into its operations as operating costs per Mcfe were reduced significantly to
$0.44 per Mcfe in 1998 versus $0.59 per Mcfe in 1997.

Depletion, depreciation and amortization expenses were $0.86 per Mcfe or
$31.5 million in 1998 and $0.83 per Mcfe or $19.1 million in 1997. The higher
rate reflects investments in pipeline infrastructure, approximately $10 million
in total over the two-year period.

Selling, general and administrative expenses increased by 67% to $5.5
million in 1998 from $3.3 million in 1997, reflecting a full year of Blazer
Energy operations and higher development activity.

Interest expense increased from $21.6 million in 1997 to $38.9 million in
1998 as a result of the Blazer Energy acquisition which was funded principally
by additional borrowings from Statoil Energy Holdings. Borrowings from Statoil
Energy Holdings were subject to 8% annual rate of interest.

Income before taxes increased from $8.0 million in 1997 to $12.8 million in
1998. Eastern States was able to use approximately $2.2 million of tax credits
in 1997 to reduce income taxes. This as well as other available credits allowed
Eastern States to realize an income tax benefit of $1.2 million in 1997, while
it had a tax expense of $4.4 million in 1998.

FISCAL YEAR ENDED DECEMBER 31, 1997 COMPARED TO FISCAL YEAR ENDED DECEMBER 31,
1996

Revenue increased 29% from $18.2 million in 1996 to $65.4 million in 1997,
which is directly attributable to the July 1, 1997 Blazer Energy acquisition.
Production increased from 17.8 MMcfe/day to 100.0 MMcfe/day and accordingly,
total volume increased 254% from 6.5 Bcfe produced in 1996 to 23.0 Bcfe produced
in 1997. Since the realized selling price was approximately $2.81 per Mcfe in
both periods, the above revenue increase is solely attributable to the increase
in production as a result of the Blazer Energy acquisition.

Operating expenses increased from $2.7 million in 1996 to $13.5 million in
1997. This increase was the direct result of the Blazer Energy acquisition and
generally higher development activity.

Depletion, depreciation and amortization expenses were $0.83 per Mcfe, or
$19.1 million, in 1997 and $0.73 per Mcfe, or $4.8 million, in 1996. This dollar
increase is directly related to the increased production volumes resulting from
the Blazer Energy acquisition.

Selling, general and administrative expenses increased from $1.6 million in
1996 to $3.3 million in 1997, due to the additional office personnel and related
expenses associated with the Blazer Energy acquisition.

Interest expense increased from $4.3 million to $21.6 million as a result
of increased borrowings from Statoil Energy Holdings to fund the Blazer Energy
acquisition. Borrowings from Statoil Energy Holdings were based on a fixed
interest rate of 8% per annum.

Income before income taxes increased from $4.8 million in 1996 to $8.0
million in 1997. In 1997, Eastern States realized $2.2 million of tax credits.
This, along with other available credits, resulted in a tax benefit of $1.2
million in 1997, compared to tax expense of $1.0 million in 1996.

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LIQUIDITY AND CAPITAL RESOURCES

Eastern States' primary capital resources are net cash provided by
operating activities and net proceeds from financing activities, including
borrowings from Statoil Energy Holdings. We expect our future capital
requirements, primarily consisting of development expenditures, to be funded by
cash flow from operations and financing activities.

Our levels of cash flows and earnings depend on many factors, including the
price of natural gas and our ability to maintain low operating costs and
overhead. We cannot predict natural gas prices which fluctuate based on market
conditions and seasonality. Our average realized natural gas price was $2.81 per
Mcfe for each of 1996 and 1997 and decreased to $2.61 per Mcfe in 1998.

For the six month period ended June 30, 1999, our net development
expenditures of approximately $21 million were entirely funded by net cash
provided from operating activities in the amount of approximately $24.8 million.

Cash provided by operating activities was $40.5 million, $12.2 million, and
$10.3 million in 1998, 1997, and 1996, respectively. The increase from 1997 to
1998 was primarily due to increased revenues and production associated with the
Blazer Energy acquisition. Before changes in working capital, cash flow from
operations was $43.7 million, $24.4 million, and $9.6 million in 1998, 1997, and
1996, respectively. For the year 1999, our capital expenditures are expected to
be $70 million. For the year 2000, our capital expenditures are expected to be
approximately $65 million.

FINANCIAL CONDITION

Total assets increased 5.1% from $626 million at December 31, 1997 to $658
million at December 31, 1998, primarily because of development drilling. As of
December 31, 1998, total capitalization of Eastern States was $631 million, of
which 80% was long-term debt. This compares with capitalization of $606 million
at December 31, 1997, of which 83% was long-term debt.

In an effort to improve Eastern States' liquidity and financial condition,
in August 1999, Statoil Energy Holdings agreed to combine and extend to December
31, 2001 the final repayment dates of various notes payable to Statoil Energy
Holdings aggregating approximately $505 million at December 31, 1998. Of the
amount rescheduled, $428 million was originally due to be paid in June 2000 with
the remainder being payable during 1999. This note has an 8% annual rate of
interest, payable semi-annually on January 1 and July 1 each year. At September
30, 1999, the total amount of outstanding indebtedness under the note payable to
Statoil Energy Holdings was approximately $505 million.

WORKING CAPITAL

Eastern States generally uses available cash to minimize intercompany
indebtedness and, therefore, maintains minimal cash and cash equivalent
balances. Short-term liquidity needs are satisfied by either advances from
Statoil Energy or Statoil Energy Holdings. Working capital of $13.2 million at
December 31, 1998 is primarily attributable to the excess of accounts receivable
over accounts payable.

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CAPITAL EXPENDITURES

The table below sets forth the components of our historical capital
expenditures for the two-years ended December 31, 1997 and 1998 and the
six-month periods ended June 30, 1998 and 1999.

YEAR ENDED SIX MONTHS
DECEMBER 31, ENDED JUNE 30,
------------------ -----------------
1997 1998 1998 1999
-------- ------- ------- -------
(IN THOUSANDS)

Exploration................................... $ 2,531 $ 2,427 $ 1,063 $ 1,000
Development................................... 22,743 69,667 20,696 22,219
Lease acquisition............................. 1,401 345 (225) 205
Proved property acquisition................... 567,135 8,403 2,368 (1,826)
-------- ------- ------- -------
Total............................... $593,810 $80,842 $23,902 $21,598
======== ======= ======= =======

Our ability to maintain and increase our operating income and cash flow is
dependent upon continued capital spending. We expect our capital expenditures in
1999 to be approximately $70 million and approximately $65 million in the year
2000. We currently expect to drill 200 to 230 net development wells in the
Appalachian Basin during 1999. Our level of capital expenditures may vary in the
future depending on a number of factors, including energy market conditions and
other related economic factors. We have no material long-term commitments
associated with expenditure plans.

Management believes that expected cash flow from operations supplemented by
borrowings, as needed, from Statoil Energy Holdings will be sufficient to fund
its capital expansion plans and working capital requirements. Future cash flows,
however, are dependent on a number of variables, such as the level of production
of natural gas and oil and the sales price of natural gas and oil. Accordingly,
management cannot guarantee that future operations will provide cash in
sufficient amounts to maintain current levels of capital expenditures or to meet
our debt service requirements.

To date, we have not spent significant amounts to comply with environmental
or safety regulations, and we currently do not expect to do so during 1999.
However, developments such as new regulations, enforcement policies or claims
for damages could result in significant future costs.

YEAR 2000

"Year 2000," or the ability of computer systems to process dates with years
beyond 1999, affects almost all companies and organizations. Computer systems
that are not Year 2000 compliant by January 1, 2000 may cause material adverse
effects to companies and organizations that rely upon those systems. Continuity
of our operations in January 2000 will depend not only on the performance of our
computer systems, but also on the compliance of computer systems and
computer-controlled equipment of third parties. These third parties include oil
and natural gas purchasers and significant service providers such as electric
utility companies and natural gas plant, pipeline and gathering system
operators.

Some of Eastern States' critical field equipment, such as natural gas
compressors, are partially controlled or regulated by embedded computer chips.
Based on a preliminary review of all operating areas, Eastern States has
identified no significant compliance exceptions. Based on its review,
remediation efforts and the results of testing to date, Eastern States does not
believe that timely modification of its computer systems for Year 2000
compliance represents a material risk. Eastern States estimates that total costs
related to Year 2000 compliance efforts will be approximately $200,000 of which
approximately $130,000 has been incurred and expensed through September 30,
1999.

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Eastern States has prepared contingency plans in the event of potential
problems resulting from failure of Eastern States' or significant third party
computer systems and compressors on January 1, 2000. As part of its contingency
plans, Eastern States will have certain key employees working on both December
31, 1999 and January 1, 2000 to determine that Eastern States' computer systems
and compressors continue to operate normally. Eastern States anticipates minimal
problems will be encountered which would affect trust assets, but the most
reasonably likely worst scenario is the loss of production from 10% to 20% of
the underlying wells for several days in January 2000 due to compressors not
properly functioning. Such loss is estimated to be less than 1% of projected
year 2000 revenue.

NEW ACCOUNTING STANDARDS

We will be required to comply with the provisions of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" which must be
adopted for fiscal years beginning after June 15, 2000. SFAS No. 133 requires
that derivatives be reported on the balance sheet at fair value and, if the
derivative is not designated as a hedging instrument, changes in fair value must
be recognized in earnings in the period of change. If the derivative is
designated as a hedge and to the extent such hedge is determined to be
effective, changes in fair value are either offset by the change in fair value
of the hedged asset or liability, if applicable, or reported as a component of
other comprehensive income in the period of change, and subsequently recognized
in earnings when the offsetting hedged transaction occurs. The definition of
derivatives has also been expanded to include contracts that require physical
delivery of oil and gas if the contract allows for net cash settlement. We
primarily use derivatives to hedge product price and interest rate risks. These
derivatives are recorded at cost, and gains and losses on such derivatives are
reported when the hedged transaction occurs. Accordingly, adoption of SFAS No.
133 will have an impact on our reported financial position, and although such
impact has not been determined, it is currently not believed to be material.
Adoption of SFAS No. 133 should have no significant impact on reported earnings,
but could materially affect comprehensive income.

PRODUCTION IMBALANCES

We have only immaterial gas production imbalance positions which result
from the balancing of accounts relating to natural gas volumes on our gathering
systems and third party gathering systems that we utilize.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We use derivative financial instruments for hedging purposes, including
swap agreements and commodity futures, swaps, and option agreements. These
financial and commodity-based derivative contracts are used to limit the risks
of natural gas price changes. Gains and losses on these derivatives are entirely
offset by losses and gains on the respective hedged exposures.

Our board of directors has adopted a policy governing the use of derivative
instruments, which requires that all derivatives we use relate to an underlying,
offsetting position, anticipated transaction or firm commitment. The policy
prohibits the use of speculative, highly complex or leveraged derivatives. The
policy also requires review and approval by our president of all risk management
programs using derivatives and all derivative transactions. These programs are
also periodically reviewed by our board of directors.

Hypothetical changes in natural gas prices chosen for the estimated
sensitivity effects are considered to be reasonably possible near-term changes
generally based on consideration of past fluctuations for each risk category. It
is not possible to accurately predict future changes in natural gas prices.
Accordingly, these hypothetical changes may not necessarily be an indicator of
probable future fluctuations.

COMMODITY PRICE RISK

Currently, Eastern States hedges a portion of the market risks associated
with its natural gas sales. During 1998, we entered into gas futures contracts
and gas basis swap agreements to reduce exposure to price volatility in the
physical markets. As of December 31, 1998, outstanding futures contracts had a
fair value gain of $8.4 million and outstanding basis swap agreements had a fair
value gain of $2.8 million. These futures contracts and basis swap agreements
are not recorded on our balance sheet at year end, but are recorded in the month
to which the contracts relate. As of December 31, 1997, outstanding futures
contracts had a fair value loss of $2.0 million and outstanding basis swap
agreements had a fair value gain of $1.2 million.

For commodity derivatives that are permitted to be settled in cash or
another financial instrument, sensitivity effects are as follows. At year-end
1998, the aggregate effect of a hypothetical 10% change in natural gas prices
and basis would result in a $1.1 million change in the fair value of these
financial instruments. This sensitivity does not include the effects of gas
contracts that cannot be settled in cash or with another financial instrument.

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MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

Our board of directors consists of five members. Their terms expire at
Eastern States' next annual meeting.

The board of directors elects our executive officers annually and those
executive officers serve at the discretion of the board of directors.

Information concerning our current directors and executive officers is
provided below.

NAME AGE POSITION
- ---- --- --------

Johan Nic Vold............................ 52 Chairman of the Board and Director
David A. Dresner.......................... 51 Director
Kristian B. Hausken....................... 47 Director
Jon A. Jacobsen........................... 41 Director
Thor Otto Lohne........................... 42 Director
Clifton A. Brown.......................... 50 President and Chief Executive Officer
Stevens V. Gillespie...................... 42 Senior Vice President and Chief Financial
Officer
James E. Cochran.......................... 38 Senior Vice President -- Operations
Jeffrey E. Fulmer......................... 38 Vice President -- Exploration, Development
and Land
James S. Caballero........................ 45 Vice President -- Engineering,
Acquisitions and Divestitures
Kerry W. Eckstein......................... 43 Vice President, General Counsel and
Secretary
David L. Matz............................. 51 Vice President -- Drilling and Completion

BACKGROUND OF DIRECTORS AND EXECUTIVE OFFICERS

Johan Nic Vold has served as Executive Vice President of The Statoil Group
since 1988, and has served as Chairman of Statoil Energy's and Eastern States'
Boards of Directors since April 1999.

David A. Dresner has served as President and Chief Executive Officer of
Statoil Energy since June 1996, and as President of Eastern States from 1994
until July 1999. He served as President and Chief Operating Officer for Statoil
Energy and its predecessor from August 1991 through May 1996. Mr. Dresner has
served as a director of Statoil Energy since August 1991 and Eastern States
since 1994.

Kristian B. Hausken has served as Senior Vice President of Strategic
Projects and Restructuring for The Statoil Group since January 1999. From 1993
to 1998, Mr. Hausken served as Senior Vice President of Natural Gas Business
Development of Statoil Energy. He has served as an employee of The Statoil Group
since 1981, and as a Vice President since 1989. He was elected to the Boards of
Directors of Statoil Energy and Eastern States in June 1996.

Jon A. Jacobsen has served as a Senior Vice President of Finance for The
Statoil Group since June 1998 and has served on the Boards of Directors of
Statoil Energy and Eastern States since May 1998. From January 1992 to June
1998, he served with Den Norske Bank (DnB) in positions relating to the energy
and international finance industry, including management of the Asian group
activities for DnB in Singapore.

Thor Otto Lohne has served as the General Manager of the Gas Division of
Statoil (UK) Gas and Chairman of Alliance Gas Limited since August 1996.
Alliance Gas Limited is a marketing subsidiary of The Statoil Group in the
United Kingdom. He joined The Statoil Group in 1983. He was elected to the
Boards of Directors of Statoil Energy and Eastern States in April 1999.

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127

Clifton A. Brown has been President and Chief Executive Officer of Eastern
States since July 1999. From June 1996 to July 1999, he served as Executive Vice
President of Eastern States. Since June 1996 he has also served as Executive
Vice President of Statoil Energy and Statoil Energy's subsidiaries engaged in
natural gas production and development operations, including Eastern States. He
also served as Senior Vice President of Statoil Energy from January 1994 to June
1996.

Stevens V. Gillespie has served as Senior Vice President and Chief
Financial Officer of Eastern States since July 1999. Since April 1996 he has
also served as Senior Vice President with Statoil Energy and Eastern States,
responsible for management of the company's Producer Services division. From
1984 to 1996, he served as Chief Financial Officer for Statoil Energy and its
predecessor companies.

James E. Cochran has served as Senior Vice President -- Operations of
Statoil Energy and Eastern States since January 1999 and previously served as
Vice President of Eastern States from July 1997 to January 1999. From January
1988 to June 1997, he performed consulting services for various oil and gas
industry clients, including Eastern States. Since June 1984, he has also owned
and operated Big Sandy Oil Company, which conducts natural gas exploration and
production in the Western Pennsylvania region of Appalachian Basin.

Jeffrey E. Fulmer has served as Vice President -- Exploration, Development
and Land of Statoil Energy and Eastern States since July 1996. From 1989 to July
1996, he held the positions of Director -- Exploration, Manager Exploration
Special Projects, and Project Geologist with Statoil Energy and its predecessor
companies.

James S. Caballero has served as Vice President -- Engineering,
Acquisitions and Divestitures of Statoil Energy and Eastern States since 1994.
From 1990 to 1994, he served as Vice President -- of Engineering, Acquisitions
and Divestitures of Statoil Energy's predecessor companies.

Kerry W. Eckstein has served as Vice President, General Counsel and
Secretary to Eastern States since July 1999 and as Counsel to Statoil Energy
since June 1997. From June 1995 to June 1997, he was the owner and operator of
the Thames Group, which conducted investments in oil and gas and other projects.
From 1990 to 1995, he served as Senior Attorney for the international
exploration and production division of Atlantic Richfield Company.

David L. Matz has served as a Vice President -- Drilling and Production
since joining Eastern States' predecessor in 1990.

DIRECTORS' COMPENSATION

All directors are also employees of our affiliates and receive no
additional compensation for service on the board of directors.

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128

EXECUTIVE COMPENSATION

The table below provides compensation information for our Chief Executive
Officer and the four other most highly compensated executive officers for the
year ended December 31, 1998.

SUMMARY COMPENSATION TABLE

LONG-TERM COMPENSATION
-------------------------------
SECURITIES
ANNUAL COMPENSATION OTHER UNDERLYING
---------------------- ANNUAL OPTIONS/ ALL OTHER
SALARY($) BONUS($) COMPENSATION($)(2) SARS(#) COMPENSATION($)(3)
---------- --------- ------------------ ---------- ------------------

Clifton A. Brown(1)........... 251,666 67,953 -- 15,000 5,620
President and Chief
Executive Officer
Stevens V. Gillespie.......... 185,000 36,920 -- 6,200 5,506
Senior Vice President, Chief
Financial Officer and
Treasurer
James Cochran................. 125,000 19,526 -- 5,000 220
Senior Vice President --
Operations
James S. Caballero............ 125,000 20,776 -- 3,300 3,976
Vice
President -- Engineering,
Acquisitions and
Divestitures
Jeffrey E. Fulmer............. 125,000 23,901 -- 3,300 4,098
Vice
President -- Exploration,
Development and Land

- ---------------

(1) Mr. Dresner served as President of Eastern States at December 31, 1998. He
also serves as President of Statoil Energy and most other U.S. subsidiaries
of The Statoil Group. Effective July 1999, Mr. Dresner resigned as Eastern
States' President. At such date, Clifton A. Brown, who served as Eastern
States' Executive Vice President, was appointed President. During 1998,
approximately 30% of Mr. Dresner's compensation was allocated to Eastern
States.

(2) Amounts do not include perquisites and other personal benefits, securities
or property, because the total amount of such compensation did not exceed
the lesser of $50,000 or 10% of the total of annual salary and bonus
reported for the named executive.

(3) In the case of Messrs. Brown, Gillespie, Caballero and Fulmer, includes a
$5,000, $5,000, $3,594 and $3,751 employee match for Statoil Energy's 401(k)
plan and a $620, $506, $382 and $347 yearly life insurance premium. In the
case of Mr. Cochran, includes a $220 life insurance premium.

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The following table shows information concerning grants of stock options
and stock appreciation rights, or SARs, during 1998 for officers named in the
Summary Compensation Table.

PERCENTAGE POTENTIAL REALIZED
OF TOTAL VALUE AT
NUMBER OF OPTIONS/ ASSUMED
SECURITIES SARS ANNUAL RATE OF
UNDERLYING GRANTED TO STOCK PRICE APPRECIATION
OPTIONS/ EMPLOYEES EXERCISE FOR OPTION TERM(1)
SARS IN PRICE EXPIRATION -------------------------
NAME GRANTED 1998(2) ($/SHARE) DATE 5%($) 10%($)
- ---- ---------- ---------- --------- ---------- ----------- -----------

Clifton A. Brown........... 15,000 7.88% $15.06 8/6/2008 $11,295.00 $22,590.00
Stevens V. Gillespie....... 6,200 3.26% 15.06 8/6/2008 $ 4,668.60 $ 9,337.20
James Cochran.............. 5,000 2.63% 15.06 8/6/2008 $ 3,765.00 $ 7,530.00
James S. Caballero......... 3,300 1.73% 15.06 8/6/2008 $ 2,484.90 $ 4,969.80
Jeffrey E. Fulmer.......... 3,300 1.73% 15.06 8/6/2008 $ 2,484.90 $ 4,969.80

- ---------------

(1) Based on the fair market value at the date of grant and the stated annual
appreciation rate, compounded annually, for the option term of ten years.
The assumed annual appreciation rates of 5% and 10% were established by the
SEC and therefore are not intended to forecast possible future appreciation,
if any, of the common stock. However, the total potential realized value
shown for the above named executives represents less than 1.5% of the total
appreciation all stockholders would realize.

(2) Based on total options granted by Statoil Energy.

OPTION/SAR GRANTS IN 1998
INDIVIDUAL GRANTS

Options granted under the Statoil Energy Amended and Restated Incentive
Compensation Plan are granted at fair market value at the date of grant and
generally vest over five years and expire ten years after the date of grant.
Shares issued pursuant to option exercise are transfer restricted. See
"-- Employee Shareholders Agreement".

The following table shows information regarding stock options and SARs
exercised during 1998 by the officers named in the Summary Compensation Table
and 1998 year-end values.

AGGREGATED OPTION/SAR EXERCISES IN 1998 AND DECEMBER 31, 1998 OPTION/SAR VALUES

NUMBER OF SHARES VALUE OF
UNDERLYING UNEXERCISED UNEXERCISED IN-THE-MONEY
SHARES OPTIONS/SARS AT OPTIONS/SARS AT
ACQUIRED 12/31/98(#) 12/31/98 ($)
ON VALUE --------------------------- ---------------------------
NAME EXERCISE(#) REALIZED($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- ----------- ----------- ----------- ------------- ----------- -------------

Clifton A. Brown....... -- $ -- 32,500 37,500 $112,190 $48,810
Stevens V. Gillespie... -- -- 42,950 13,440 216,942 8,970
James E. Cochran....... -- -- -- 5,000 -- --
James S. Caballero..... 4,000 20,400 4,640 8,610 15,010 11,896
Jeffrey E. Fulmer...... -- -- 3,380 7,820 10,609 9,797

EMPLOYMENT AND CHANGE IN CONTROL AGREEMENTS

Effective February 1, 1999, Messrs. Brown and Gillespie entered into
individual employment agreements with Statoil Energy pursuant to which they
serve as executive officers. Mr. Brown's agreement has a term of 30 months,
which is automatically extended so that at all times the term is 30 months from
the current date. Mr. Gillespie's agreement has a term of 24 months, which is
automatically extended so that at all times the term is 24 months from the
current date. The employment agreements contain customary non-compete and
non-solicitation provisions which terminate at the later of:

- one year after termination of employment or

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130

- the end of the period after which the executive continues to receive
severance payments after a change in control.

Mr. Brown's agreement provides for an annual base salary of not less than
$260,000, and Mr. Gillespie's agreement provides for an annual base salary of
not less than $190,000, both of which may be increased at the discretion of the
Board of Directors of Statoil Energy. In addition, Messrs. Brown and Gillespie
are eligible to receive:

- an incentive bonus based on the financial performance of Eastern States
and the evaluation of each of Mr. Brown's and Mr. Gillespie's performance
by the Board of Directors of Statoil Energy;

- stock options awarded at the discretion of Statoil Energy's Board of
Directors consistent with historical practices;

- reimbursement of all reasonable expenses; and

- other benefits including, but not limited to, any retirement benefit
plan, disability, group life, sickness, accident and health insurance
programs provided by Statoil Energy to executives.

Eastern States may terminate either employment agreement at any time
without cause. Messrs. Brown and Gillespie are then entitled to receive "base
compensation" for the longer of one year, or the time period remaining under the
term of the agreement. "Base compensation" is defined as the executive's annual
base salary plus the average of all incentive bonuses paid to the executive
during the previous three years.

Change in Control. Each employment agreement further states that if, within
two years following a change in control (as defined below) the executive is
terminated without cause or terminates his employment for good reason, then the
executive will be entitled to a severance payment in an amount equal to:

- two and one-half times Mr. Brown's base compensation or two times Mr.
Gillespie's base compensation, respectively, plus

- an amount to compensate for lost benefits equal to the lesser of:

-- 10% of the base compensation or

-- $20,000 adjusted for inflation.

In addition, all non-vested stock options will vest automatically upon the
executive's termination within two years of a change in control or a materially
adverse change in the executive's employment and be exercisable until the first
anniversary of the executive's termination of employment with Statoil Energy.

A "change in control" shall be deemed to have occurred if:

- any person other than The Statoil Group, its affiliates or Statoil Energy
or an employee benefit plan of Statoil Energy acquires the beneficial
ownership of any voting security of Statoil Energy and after the
acquisition the acquiring person is the beneficial owner of voting
securities representing more than 50% of the total voting power of all
the outstanding voting securities of Statoil Energy; or

- the stockholders of Statoil Energy, that is, The Statoil Group, approve a
merger, consolidation or reorganization of Eastern States, unless

-- the transaction results in more than 50% of the voting power after the
transaction beneficially owned by holders of voting securities of the
Eastern States prior to the transaction, with substantially the same
voting power or

-- the members of the Eastern States' board of directors prior to the
transaction constitute 50% or more of the members of its board of
directors after the first vote to elect its members following the
transaction; or

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131

- the stockholders of Eastern States approve a plan of complete
liquidation, dissolution or disposition of substantially all of the
assets or business of Eastern States; or

- Eastern States sells or transfers the business unit or division for which
the employee has primary responsibility to an entity other than The
Statoil Group, Eastern States or an entity controlled by The Statoil
Group or Eastern States and this other entity does not offer the employee
a position with substantially similar responsibilities and duties and the
base compensation and other benefits provided under the employment
agreement.

Upon the sale of Statoil Energy or a "change in control" and a termination
without cause or for good reason, Messrs. Brown and Gillespie would be entitled
to payments in the amount approximating $870,000 and $500,000, respectively.

In the event of termination for cause, the executive will be entitled to no
further compensation or payment.

Messrs. Brown and Gillespie may terminate their employment for good reason.
If the executive resigns for good reason, he is entitled to his base
compensation for the longer of one year or the remainder of the term of the
agreement.

Ninety percent of the compensation owed to Mr. Brown and Mr. Gillespie
under these employment agreements is paid for and allocated to Eastern States.
The remaining 10% is allocated to its affiliate Eastern States Exploration
Company, an indirect wholly owned subsidiary of Statoil Energy, Inc.

SEVERANCE POLICY

In connection with The Statoil Group's intention to sell its ownership
interest in Statoil Energy, Statoil Energy has implemented an employee retention
program, effective as of October 13, 1999, to provide job security for full-time
employees, including Messrs. Cochran, Caballero and Fulmer, of Statoil Energy
and its majority-owned subsidiaries, including Eastern States. The employment
security provisions, which are not applicable to executives with employment
agreements, such as Messrs. Brown and Gillespie, will extend from October 13,
1999 through the first anniversary of the closing of any sale of The Statoil
Group's interest in Statoil Energy.

Severance benefits will only be offered to employees who are involuntarily
terminated "without cause," meaning any employee terminated for failure to
relocate more than fifty miles from his present office, or who voluntarily
leaves his employment "with justification," meaning any employee whose salary is
reduced by at least 10% of his base compensation as of January 1, 2000 or who is
required to relocate to a new location more than fifty miles from his present
office. Each eligible employee must execute, prior to receiving any benefits, a
general release, a confidentiality agreement and a
non-competition/non-solicitation agreement applicable for the period during
which base compensation is extended.

If the above conditions apply, each of Messrs. Cochran, Caballero and
Fulmer will receive a continuation of their base compensation after termination
for a minimum of nine months and a maximum of 12 months. They will also be
entitled to receive a bonus based on the greater of their target bonus for the
year 2000 or the average of their bonuses from the prior two years. Health
benefits will also be extended for the period during which he receives salary
continuation under the retention program. Under this employee retention program,
Messrs. Cochran, Caballero and Fulmer would receive continued base salary, bonus
and benefits approximating $125,000, $150,000 and $160,000, respectively.

AMENDED AND RESTATED INCENTIVE COMPENSATION PLAN

Statoil Energy has an Amended and Restated Incentive Compensation Plan
designed to reward and incentivize employees of Statoil Energy and its
subsidiaries based on the financial performance of Statoil Energy and its
subsidiaries and the personal performance of the employee. Incentives offered
under this plan include:

A-37
132

- incentive stock options;

- non-qualified stock options;

- stock awards;

- restricted stock awards; and

- performance stock awards.

The Incentive Plan is administered by a committee appointed by Statoil
Energy's board of directors. Only officers and employees of Statoil Energy and
its subsidiaries, including Eastern States, are eligible for such awards. The
maximum aggregate number of shares of common stock which may be issued under the
Incentive Plan is 1,500,000 shares. The Incentive Plan will terminate on January
6, 2002.

Incentive Stock Options. Incentive stock options must satisfy the
requirements of Section 422(b) of the Internal Revenue Code of 1986, as amended.
All incentive stock options must be granted by January 6, 2002 and expire no
later than ten years after the date of grant. The exercise price for each
incentive stock option may not be less than the fair market value of the
underlying common stock. No incentive stock options may be granted to any
employee who, at the time the option is granted, would own more than 10% of the
total combined voting power of all classes of stock unless:

- the exercise price is equal to at least 110% of the fair market value of
the underlying stock; and

- the option is not exercisable after the expiration of five years from the
grant date.

Non-qualified Stock Options. The exercise price of non-qualified stock
options may be determined by the committee, provided that such price is not less
than 33% of the fair market value of the underlying stock on the grant date. The
term of each non-qualified stock option cannot be longer than ten years from the
date of the grant. Each non-qualified stock option will vest and become
exercisable in accordance with the provisions set forth in each stock option
agreement. Notwithstanding any such vesting provisions, any option, whether
incentive or non-qualified, will become fully vested and exercisable as follows:

- when the employee dies, becomes disabled or attains age 65 while employed
by Statoil Energy or one of its subsidiaries; or

- when the employee's employment is terminated within two years following a
change-in-control.

Stock Awards and Restricted Stock Awards. A stock award of common stock is
issued by Statoil Energy to an employee, without other payment therefor, as
additional compensation for his service to Statoil Energy or one of its
subsidiaries. A restricted stock award is common stock issued, without other
payment, but subject to certain restrictions on sale or transfer as determined
by the committee. All employees receiving a restricted stock award must enter
into an escrow agreement with Statoil Energy outlining the conditions of such
award.

Performance Stock Awards. Performance stock awards are contingent rights to
receive shares dependent upon the achievement of certain performance objectives.
Each performance stock award is evidenced by a written agreement outlining the
specific objectives to be achieved. If the employee attains such objectives,
Statoil Energy will issue shares of common stock equal to the number of
performance stock awards granted by the committee to the employee.

Termination of Employment. Any stock option, whether incentive or
non-qualified, held by an employee and not exercised will be immediately
cancelled upon termination of employment by Statoil Energy or one of its
subsidiaries for cause or as a result of voluntary termination by the employee.
If the employee is terminated for any reason other than for cause, any vested
and unexercised option, whether incentive or non-qualified, will continue to be
exercisable in accordance with the terms of its stock option agreement for a
period of ninety days following the notice of termination.

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133

If the employee is terminated for any reason, any restricted stock award or
performance stock award not already issued and vested will be cancelled
immediately.

EMPLOYEE SHAREHOLDER AGREEMENT

Each employee who receives an incentive under the Incentive Plan is
required to enter into a Shareholders Agreement with Statoil Energy which:

- prohibits the transfer of shares received pursuant to option exercises
and other incentive grants to any person other than another holder who is
an employee at the time of the transfer, the holder's immediate family or
to a Statoil Energy affiliate;

- grants a put option to the holder exercisable during April and October of
each year at fair market value established according to a formula
provided in the agreement; and

- provides for the mandatory repurchase at fair market value upon
termination or death of the employee of all shares owned by the employee
as a result of awards under the Incentive Plan.

If, within one year from the repurchase of common stock as a result of an
employee's termination without cause or resignation for good reason there is:

- an underwritten public offering;

- a merger, consolidation or sale of all or substantially all assets; or

- a transfer of at least 25% of Statoil's capital stock of Statoil Energy,
any of which results in a change in control, then,

Statoil Energy will pay to the employee the difference between the value of a
share sold in such transaction and the price at which Statoil Energy repurchased
the employee's shares.

SECURITY OWNERSHIP OF MANAGEMENT AND CERTAIN BENEFICIAL OWNERS

Eastern States is a privately held company. All of the outstanding shares
of common stock of Eastern States are owned by Statoil Energy Holdings, Inc., a
wholly owned subsidiary of Statoil Energy.

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134

INDEX TO FINANCIAL STATEMENTS

EASTERN STATES OIL & GAS, INC.

EASTERN STATES OIL & GAS, INC.
Consolidated Financial Statements
Report of Independent Auditors......................... AF-2
Consolidated Balance Sheets as of December 31, 1997 and
1998.................................................. AF-3
Consolidated Statements of Operations for the years
ended December 31, 1996, 1997 and 1998................ AF-4
Consolidated Statements of Stockholder's Equity........ AF-5
Consolidated Statements of Cash Flows for the years
ended December 31, 1996, 1997 and 1998................ AF-6
Notes to Consolidated Financial Statements............. AF-7

Unaudited Consolidated Financial Statements
Unaudited Consolidated Balance Sheets as of December
31, 1998 and June 30, 1999............................ AF-18
Unaudited Consolidated Statements of Operations for the
six month periods ended June 30, 1998 and 1999........ AF-19
Unaudited Consolidated Statements of Cash Flows for the
six month periods ended June 30, 1998 and 1999........ AF-20
Notes to Unaudited Consolidated Financial Statements... AF-21

Unaudited Pro Forma Consolidated Financial Statements
Unaudited Pro Forma Consolidated Balance Sheet as of
June 30, 1999......................................... AF-23
Unaudited Pro Forma Consolidated Statement of
Operations for the year ended December 31, 1998....... AF-24
Unaudited Pro Forma Consolidated Statement of
Operations for the six months ended June 30, 1999..... AF-25
Notes to Unaudited Pro Forma Consolidated Financial
Statements............................................ AF-26

DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
Report of Independent Auditors............................ AF-28
Consolidated Income Statement for the fiscal year ended
September 30, 1996..................................... AF-29
Consolidated Statement of Cash Flows for the year ended
September 30, 1996..................................... AF-30
Notes to Consolidated Financial Statements................ AF-31

Unaudited Domestic Operations of Blazer Energy Corp. and
Subsidiary
Unaudited Consolidated Income Statement for the nine
months ended June 30, 1997............................ AF-39
Unaudited Consolidated Statement of Cash Flows for the
nine months ended June 30, 1997....................... AF-40
Notes to Unaudited Consolidated Financial Statements... AF-41

AF-1
135

REPORT OF INDEPENDENT AUDITORS

Board of Directors and Stockholder
Eastern States Oil & Gas, Inc.

We have audited the accompanying consolidated balance sheets of Eastern
States Oil & Gas, Inc. as of December 31, 1997 and 1998, and the related
consolidated statements of operations, stockholder's equity and cash flows for
each of the three years in the period ended December 31, 1998. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Eastern States
Oil & Gas, Inc. at December 31, 1997 and 1998, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted accounting
principles.

ERNST & YOUNG LLP

Vienna, Virginia

August 23, 1999, except for Note 12, as

to which the date is October 13, 1999

AF-2
136

EASTERN STATES OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

ASSETS

DECEMBER 31,
-------------------
1997 1998
-------- --------

Current assets
Accounts receivable -- related party...................... $ 21,795 $ 28,787
Accounts receivable -- trade, net......................... 3,928 7,732
Inventories............................................... 4,112 1,600
Prepaid expenses and other................................ 41 159
-------- --------
Total current assets.............................. 29,876 38,278
-------- --------
Property and equipment, net
Natural gas and oil properties -- full cost method (See
Note 3)................................................ 543,777 559,523
Gathering systems......................................... 46,112 56,088
Other property and equipment.............................. 3,496 4,196
-------- --------
Total property and equipment...................... 593,385 619,807
-------- --------
Deferred income taxes....................................... 2,880 --
Other assets................................................ 198 248
-------- --------
Total assets...................................... $626,339 $658,333
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Accounts payable.......................................... $ 17,389 $ 21,214
Accrued expenses.......................................... 1,691 1,136
Accrued severance and property taxes...................... 739 2,713
-------- --------
Total current liabilities......................... 19,819 25,063
-------- --------
Deferred income taxes....................................... -- 926
Long-term debt.............................................. 503,588 505,488
Intercompany liabilities.................................... 37,834 51,974
Other liabilities........................................... 363 1,801
Stockholder's equity
Common stock ($1 par value, 1,000 shares authorized,
issued and
outstanding)........................................... 1 1
Additional paid-in capital................................ 51,500 51,500
Retained earnings......................................... 13,234 21,580
-------- --------
Total stockholder's equity........................ 64,735 73,081
-------- --------
Total liabilities and stockholder's equity........ $626,339 $658,333
======== ========

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

AF-3
137

EASTERN STATES OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)

YEAR ENDED DECEMBER 31,
----------------------------
1996 1997 1998
------- ------- --------

Revenue
Natural gas and oil....................................... $18,247 $64,604 $ 95,315
Tax credit monetization................................... -- 764 9,355
------- ------- --------
18,247 65,368 104,670
------- ------- --------
Costs and expenses
Direct operating costs.................................... 2,655 13,454 15,950
Selling, general and administrative....................... 1,630 3,254 5,462
Depreciation, depletion and amortization.................. 4,783 19,073 31,517
------- ------- --------
9,068 35,781 52,929
------- ------- --------
Income from operations...................................... 9,179 29,587 51,741
Interest expense............................................ 4,338 21,608 38,952
------- ------- --------
Income before income taxes.................................. 4,841 7,979 12,789
Income tax expense (benefit)................................ 956 (1,171) 4,443
------- ------- --------
Net income.................................................. $ 3,885 $ 9,150 $ 8,346
======= ======= ========

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

AF-4
138

EASTERN STATES OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(IN THOUSANDS)

ADDITIONAL
COMMON PAID-IN RETAINED
STOCK CAPITAL EARNINGS TOTAL
------ ---------- -------- -------

Balance, December 31, 1995............................ $1 $ 1,500 $ 199 $ 1,700
Net income -- 1996.................................... 3,885 3,885
-- ------- ------- -------
Balance, December 31, 1996............................ 1 1,500 4,084 5,585
Net income -- 1997.................................... 9,150 9,150
Contribution of capital............................... 50,000 50,000
-- ------- ------- -------
Balance, December 31, 1997............................ 1 51,500 13,234 64,735
Net income -- 1998.................................... 8,346 8,346
-- ------- ------- -------
Balance, December 31, 1998............................ $1 $51,500 $21,580 $73,081
== ======= ======= =======

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

AF-5
139

EASTERN STATES OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1997 1998
-------- --------- --------

Cash flows from operating activities
Net income................................................ $ 3,885 $ 9,150 $ 8,346
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion and amortization............... 4,783 19,073 31,517
Deferred income tax expense (benefit).................. 909 (3,788) 3,806
Net changes in working capital
Accounts receivable.................................... (2,398) (22,960) (10,796)
Inventories............................................ (52) (3,920) 2,512
Prepaid expenses and other............................. (18) (12) (118)
Accounts payable and accrued expenses.................. 3,192 14,701 5,244
-------- --------- --------
Net cash provided by operating activities................... 10,301 12,244 40,511
-------- --------- --------
Cash flows from investing activities
Acquisition of natural gas and oil properties............. (31,760) (450,214) (6,812)
Other additions to natural gas and oil properties......... (24,511) (143,596) (74,030)
Disposition of natural gas and oil properties............. -- 82,300 23,957
Other property additions.................................. (518) (3,197) (1,683)
Other..................................................... 218 (102) 2,017
-------- --------- --------
Net cash used in investing activities....................... (56,571) (514,809) (56,551)
-------- --------- --------
Cash flows from financing activities
Contribution of capital................................... -- 50,000 --
Issuance of long-term debt................................ 28,267 433,955 1,900
Intercompany activity..................................... 18,003 18,610 14,140
-------- --------- --------
Net cash provided by financing activities................... 46,270 502,565 16,040
-------- --------- --------
Net change in cash and cash equivalents..................... -- -- --
Cash and cash equivalents
Beginning of year......................................... -- -- --
-------- --------- --------
End of the year........................................... $ -- $ -- $ --
======== ========= ========

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

AF-6
140

EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Company

Eastern States Oil & Gas, Inc. ("Company") is a wholly-owned subsidiary of
Statoil Energy Holdings, Inc. ("SEH") and is engaged in natural gas and oil
exploration and production in the states of Ohio, West Virginia and Kentucky.
SEH is a wholly-owned subsidiary of Statoil Energy, Inc. ("STEN") and holds
STEN's interests in various operating entities engaged in energy related
activities.

Principles of consolidation

The consolidated financial statements include the accounts of the Company,
its wholly-owned subsidiaries and its proportionate share of the assets,
liabilities, revenue and expenses of various oil and gas development ventures.
All intercompany accounts and transactions have been eliminated.

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect certain reported amounts of assets and liabilities and
disclosure of contingent liabilities at the date of the financial statements.
These estimates and assumptions also affect certain amounts of reported revenues
and expenses. Actual results could differ from those estimates.

Derivatives

The Company uses derivatives to hedge product price risks, as opposed to
their use for trading purposes. Gains and losses on commodity futures contracts
and other price risk management instruments are recognized in oil and gas
revenues when the hedged transaction occurs. Cash flows related to derivative
transactions are included in operating activities. In order to qualify for hedge
accounting, the derivative instrument must be designated and effective as a
hedge. If the derivative does not meet these requirements, the derivative
instrument is marked-to-market in income. In the event the hedged item matures,
is sold, or is terminated, the realized and unrealized gains and losses are
recognized in income coincidental with the transaction.

Accounts receivable

Accounts receivable arises primarily from the sale of natural gas. The
Company performs ongoing credit evaluations of its customers to minimize its
exposure to credit risk. The Company's allowance for doubtful accounts, which is
reflected in the consolidated balance sheets as a reduction in accounts
receivable, was $1.0 million and $0.2 million at December 31, 1997 and 1998,
respectively.

Concentration of credit risk

In 1996, 1997 and 1998, sales to Statoil Energy Services, Inc. ("SES"), an
affiliated company, were 85%, 83% and 59%, respectively, of total revenues.
Sales to an unaffiliated purchaser were 23% in 1998. There were no other
customers with purchases of greater than 10% of total revenues for 1996, 1997
and 1998.

Inventories

Inventories, consisting primarily of operating supplies and other materials
used in well drilling, are stated at the lower of cost or market using the
first-in, first-out method.

AF-7
141
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Property and equipment

In accounting for natural gas and oil exploration and development costs,
the Company follows the full cost method of accounting, under which all
productive and nonproductive costs associated with acquisition, exploration and
development activities are capitalized. This includes internal staff costs that
are directly associated with acquisition, exploration and development activities
but does not include any costs related to production or similar activities.
Internal costs include Company staff time related to the acquisition,
exploration and development of natural gas and oil properties and are
capitalized on the basis of periodic time studies.

Natural gas and oil properties at December 31, 1998 include costs of $39.4
million of acquisition costs and $1.1 million of exploration costs associated
with unevaluated properties. These costs were incurred in 1997 and are excluded
from capitalized costs being amortized, pending determination of the existence
of proved reserves. Depreciation, depletion and amortization of evaluated costs
is provided using the units-of-production method based on proved natural gas and
oil reserves. Estimated restoration and abandonment costs, net of salvage
credits, are taken into account in determining depreciation and depletion.
Capitalized costs may not exceed the present value of future net revenues from
production of proved natural gas and oil reserves, determined in accordance with
procedures prescribed by the Securities and Exchange Commission. When an oil and
gas property ceases economic production, the Company either sells the property
or dismantles and removes all surface equipment, plugs the wells, and restores
the property's surface in accordance with various regulations and agreements
before abandoning the property. The Company accrues the estimated future costs,
net of estimated equipment salvage values, over the property's estimated
productive life. At December 31, 1998, the Company had accrued $1.8 million for
such costs. Anticipated costs for currently proved properties that we expect to
plug and abandon total $22.4 million, primarily payable over the next 50 years.

Gathering systems are depreciated using the straight-line method over the
useful lives of assets (20 to 25 years).

Other property and equipment is stated at original cost and long-lived
assets are reviewed annually in accordance with current accounting standards.
Depreciation of other property and equipment is provided on a straight-line
basis over the useful lives of the assets (5 to 10 years for equipment). Repairs
of property and equipment are charged to expense as incurred.

Accounts payable

Accounts payable includes credit balances to the extent that checks issued
have not been presented to the Company's bank for payment. These credit balances
included in accounts payable were approximately $2.9 million and $5.2 million at
December 31, 1997 and 1998, respectively.

Revenue recognition

The Company records its natural gas and oil revenues on the entitlement
method whereby the Company recognizes revenues based upon its entitled share of
production. As of December 31, 1996, 1997, and 1998, the Company's natural gas
and oil imbalances were not material.

Natural gas measurement

The Company records estimated amounts for natural gas revenues and natural
gas purchase costs based on volumetric calculations under its natural gas sales
and purchase contracts. Variances resulting from such calculations are inherent
in natural gas sales, production, operation, measurement and administration.
Management does not believe that differences between actual and estimated
natural gas revenues are material.
AF-8
142
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Income taxes

The Company follows the asset and liability method of accounting for income
taxes. Deferred tax assets and liabilities are determined using the tax rate for
the period in which those amounts are expected to be received or paid, based on
temporary differences between the tax bases of assets and liabilities and their
reported amounts. Under this method, the effect of a change in income tax rates
on deferred tax assets and liabilities is recognized as an element of income in
the period the rate change is enacted.

Since 1997, the Company and all Statoil affiliated companies located in the
United States, participate in a tax sharing arrangement, whereby all required
federal income tax returns for 1997 and future years will be filed on a
consolidated basis. For financial reporting purposes, each company accounts for
its income taxes on a separate company basis. Any benefits or detriments
resulting from the consolidation of federal income tax returns will remain with
or be incurred by the holding company, Statoil North America, Inc. ("SNA").

Segment reporting

In accordance with Statement of Financial Accounting Standards No. 131
("SFAS 131"), Disclosures about Segments of an Enterprise and Related
Information, the Company has identified only one operating segment, which is the
exploration and production of oil and gas. All the Company's assets are located
in the United States and all of its revenues are attributable to United States
customers.

2. ACQUISITIONS AND DISPOSALS

The following acquisitions have been accounted for using the purchase
method. The results of the acquired operations are included in the accompanying
consolidated financial statements from their respective dates of acquisition:

Purchases of natural gas and oil properties from unaffiliated parties,
recorded at cost exclusive of internal cost capitalization, are as follows (in
millions):

PROVED UNPROVED GATHERING OTHER
RESERVES PROPERTIES SYSTEMS PROPERTY TOTAL
-------- ---------- --------- -------- ------

1996................................... $ 31.6 $ 0.2 $ 5.8 $ 0.3 $ 37.9
1997................................... 409.9 40.3 31.7 8.4 490.3
1998................................... 0.8 6.0 -- -- 6.8

In 1997, the Company acquired the stock of Blazer Energy Corporation
(Blazer), a wholly-owned subsidiary of Ashland Inc. for a purchase price of
$567.1 million. Blazer is engaged in the exploration, development, production,
acquisition and marketing of natural gas and oil. Subsequent to the closing of
the transaction, Blazer properties located in the Gulf of Mexico region were
sold to an affiliated company, Statoil Exploration, Inc. ("SEUS"), a
wholly-owned subsidiary of SNA for $82.3 million. In addition, in 1998, the
Company sold certain proved developed reserves along with undeveloped acreage in
approximately 400 non-producing properties for $24.0 million.

AF-9
143
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

3. PROPERTY AND EQUIPMENT

Investments in property and equipment are comprised of the following (in
thousands):

DECEMBER 31,
-------------------
1997 1998
-------- --------

Natural gas and oil properties
Proved.................................................... $523,506 $567,741
Unproved.................................................. 44,066 42,444
-------- --------
Total cost............................................. 567,572 610,185
Accumulated depletion.................................. (23,795) (50,662)
-------- --------
Net book value of natural gas and oil properties............ 543,777 559,523
-------- --------
Gathering systems
Cost...................................................... 47,931 60,507
Accumulated depletion..................................... (1,819) (4,419)
-------- --------
Net book value of gathering systems......................... 46,112 56,088
-------- --------
Other property and equipment
Cost...................................................... 4,036 5,718
Accumulated depreciation and amortization................. (540) (1,522)
-------- --------
Net book value of other property and equipment.............. 3,496 4,196
-------- --------
Net book value of property and equipment.................... $593,385 $619,807
======== ========

4. PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

It is the Company's general practice to hedge commodity price risk arising
from its unmatched firm physical commitments to purchase or sell hydrocarbon
products at fixed prices by taking offsetting positions in futures, options and
swaps (collectively, "derivative commodity instruments"). The maturity of these
derivative commodity instruments is matched closely with the underlying physical
commitment. The Company does not hold or issue derivative financial instruments
for speculative or trading purposes.

The Company is exposed to credit risk in the event of non-performance by
counterparts on natural gas forwards, options and swaps. The Company does not
anticipate non-performance by any of these counterparts. The amount of such
exposure is generally the unrealized gain on such contracts.

At December 31, the estimated pre-tax fair values determined by market
quotes, of the Company's derivative commodity instruments were as follows (in
millions):

1997 1998
---------------- -----------------
NOTIONAL FAIR NOTIONAL FAIR
VALUE VALUE VALUE VALUE
-------- ----- -------- ------

Futures............................................ $36.7 $38.2 $ 8.2 $ 10.0
Swaps.............................................. 58.1 57.2 130.3 137.7
Basis.............................................. 4.4 5.6 10.6 13.4
Options............................................ 71.6 69.0 51.4 50.6

The Company recognized a $1.2 million loss, a $4.5 million loss and a $7.1
million gain in 1996, 1997 and 1998, respectively, related to its derivative
commodity instruments. Such amounts are reflected as a component of natural gas
and oil revenue.

The carrying value of the Company's accounts receivable, accounts payable
and long-term debt approximate fair value.
AF-10
144
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities". SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded on the
balance sheet as either an asset or liability measured at its fair value. SFAS
133 requires that changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement. SFAS 133 is
effective for fiscal years beginning after June 15, 2000. The Company has not
determined the method or quantified the effects of adopting SFAS 133 on its
financial statements; however, the Company will adopt SFAS 133 effective January
1, 2001.

In November 1998, the Financial Accounting Standards Board Emerging Issues
Task Force (EITF) issued "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities" (EITF No. 98-10). The EITF provides guidance
regarding the accounting for energy trading contracts which should be applied to
financial statements issued for fiscal years beginning after December 15, 1998.
The application of EITF 98-10 will not have a significant impact on the
Company's financial statements.

5. LONG-TERM DEBT

In August 1999, the Company and SEH agreed to aggregate and extend to
December 31, 2001 the final repayment dates of various notes payable to SEH
aggregating $505.5 million. This note has an 8% annual rate of interest, payable
semi-annually on January 1 and July 1 each year.

During the years ended December 31, 1996, 1997 and 1998, the Company
recorded interest expense due to SEH of $4.8 million, $23.2 million and $40.9
million. All amounts were settled as of the respective year end dates. Interest
expense, in the amount of $0.5 million, $1.5 million and $1.9 million, relating
to unevaluated natural gas and oil properties, has been capitalized as part of
natural gas and oil properties in 1996, 1997 and 1998, respectively.

6. INCOME TAXES

The provision for income taxes is as follows (in thousands):

YEAR ENDED DECEMBER 31,
-----------------------
1996 1997 1998
---- ------- ------

Current tax expense
Federal................................................... $ -- $ 1,570 $ --
State..................................................... 47 1,047 637
---- ------- ------
Total current tax expense................................... 47 2,617 637
---- ------- ------
Deferred tax expense (benefit)
Federal................................................... 779 (3,246) 3,261
State..................................................... 130 (542) 545
---- ------- ------
Total deferred tax expense (benefit)........................ 909 (3,788) 3,806
---- ------- ------
Total income tax expense (benefit).......................... $956 $(1,171) $4,443
==== ======= ======

AF-11
145
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Deferred tax liabilities (assets) are comprised of the following (in
thousands):

DECEMBER 31,
------------------
1997 1998
------- --------

Deferred tax liabilities
Excess of book basis over tax basis:
Natural gas and oil properties......................... $ 4,317 $ 12,709
------- --------
Total deferred tax liabilities.............................. 4,317 12,709
------- --------
Deferred tax assets
Net operating loss carryforwards.......................... -- (10,181)
Minimum tax credit carryforwards.......................... (1,570) (1,570)
Other..................................................... (5,627) (32)
------- --------
Total deferred tax assets................................... (7,197) (11,783)
------- --------
Net deferred income tax liability (asset)................... $(2,880) $ 926
======= ========

The provision for income taxes differs from the amount of income tax
determined by applying the applicable statutory federal income tax rate to
pre-tax income as a result of the following (in thousands):

YEAR ENDED DECEMBER 31,
--------------------------
1996 1997 1998
------ ------- -------

Federal income tax....................................... $1,694 $ 2,793 $ 4,476
Change in valuation allowance............................ (47) -- --
Permanent items.......................................... 1 13 17
Transfer pricing adjustment.............................. (870) (2,249) (1,232)
State and local income taxes............................. 178 505 1,182
Nonconventional fuel source tax credits.................. -- (2,233) --
------ ------- -------
Total income tax expense (benefit)....................... $ 956 $(1,171) $ 4,443
====== ======= =======

As of December 31, 1998, the Company has available, for income tax
purposes, minimum tax credit carryforwards of approximately $1.5 million, which
do not expire, and net operating loss carryforwards of approximately $25.0
million, which expire in 2006 through 2018. For the years ended December 31,
1996, 1997 and 1998, the Company made income tax payments of $0.1 million, $2.6
million and $0.6 million, respectively.

7. STOCK OPTIONS

Key employees of the Company participate in a STEN sponsored incentive
compensation plan under which stock options may be granted. Each option granted
to an employee entitles the grantee to purchase one share of STEN common stock
at a price equal to its fair market value at the date of the grant. All options
generally vest over five years and expire ten years after the date of grant or
90 days after

AF-12
146
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

termination of employment, whichever is earlier. Transactions involving stock
options under the plan are summarized below:

INCENTIVE NON-
STOCK QUALIFIED OPTION PRICE
OPTIONS OPTIONS TOTAL PER SHARE
--------- --------- ------- ----------------

Outstanding at December 31, 1995................ 86,500 -- 86,500 $9.15 to $13.80
Granted....................................... 29,500 -- 29,500 $10.75
Canceled...................................... -- -- --
Exercised..................................... -- -- --
------- ------ -------
Outstanding at December 31, 1996................ 116,000 -- 116,000 $9.15 to $13.80
Granted....................................... -- 33,500 33,500 $14.92
Canceled...................................... -- -- --
Exercised..................................... (5,110) -- (5,110) $9.15
------- ------ -------
Outstanding at December 31, 1997................ 110,890 33,500 144,390 $9.15 to $14.92
Granted....................................... -- 44,350 44,350 $15.06
Canceled...................................... -- -- --
Exercised..................................... (4,000) -- (4,000) $9.15 to $10.05
------- ------ -------
Outstanding at December 31, 1998................ 106,890 77,850 184,740 $9.15 to $15.06
======= ====== =======

WEIGHTED AVERAGE
PRICE PER SHARE
----------------

Exercisable at December 31, 1996................ 64,600 -- 64,600 $10.33
======= =======
Exercisable at December 31, 1997................ 75,090 -- 75,090 $10.49
======= =======
Exercisable at December 31, 1998................ 86,690 6,700 93,390 $10.87
======= ====== =======

Management has reviewed SFAS 123, "Accounting for Stock-Based
Compensation", which outlines a fair value based method of accounting for stock
options or similar equity instruments and has elected to continue using the
intrinsic value based method of accounting, as prescribed by Accounting
Principles Board Opinion No. 25. Accordingly, no compensation expense has been
recorded in the accompanying financial statements.

Net income would be $3.8 million in 1996, $9.1 million in 1997 and $8.3
million in 1998 had the Company adopted the fair value based accounting model
set forth in SFAS 123. Under the fair value based method, the weighted average
fair values of options granted during 1996, 1997 and 1998 were $2.88, $4.00 and
$4.04, respectively. The fair value of stock options were calculated using the
minimum value method with the following weighted average assumptions for grants
in 1996, 1997 and 1998: risk free interest rate of 6.25%; no expected dividend
yield; and an expected option life of five years. The fair value of stock
options included in the pro forma results for 1996, 1997 and 1998 are not
necessarily indicative of future effects on net income.

8. RELATED PARTY TRANSACTIONS

Accounts receivable with related party consists of accrued natural gas
sales to SES.

AF-13
147
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Intercompany liabilities consist of the following (in thousands):

DECEMBER 31,
-------------------
1997 1998
-------- --------

STEN........................................................ $(14,858) $(81,773)
SES, receivable in 1998..................................... (7,502) 39,580
ESEC........................................................ (15,474) (9,781)
-------- --------
$(37,834) $(51,974)
======== ========

The intercompany activity with STEN consists of amounts due for
payroll-related costs, fixed asset additions, corporate taxes, interest payments
to SEH on behalf of the Company and other cash transactions to and from STEN.
The intercompany activity with SES relates to marketing of natural gas to SES
and fees for risk management services provided to the Company. Eastern States
Exploration Company ("ESEC") is a wholly-owned subsidiary of SEH engaged in
natural gas and oil exploration and production in Pennsylvania. The intercompany
payable to ESEC consists primarily of amounts due for drilling expenditures,
certain operating costs and other transactions related to cash management
activities.

See Note 5 for debt and interest transactions between the Company and SEH.

9. PROFIT SHARING PLAN

Substantially all full-time employees of the Company participate in a STEN
sponsored profit sharing plan that includes an employee savings feature under
Section 401(k) of the Internal Revenue Code. Participants can elect to defer up
to 15% of their total compensation through contributions to the plan and STEN
matches 50% of employee contributions up to 6% of an employee's total
compensation. Effective January 1, 1997, the vesting schedule for STEN's
contributions was shortened from seven to five years.

For the years ended December 31, 1996, 1997 and 1998, charges to income for
the Company's share of contributions to the plan aggregated $0.02 million, $0.10
million, and $0.20 million, respectively. STEN also made supplemental
contributions, a portion of which benefited Company participants, for the years
ended December 31, 1996 and 1997 in the amounts of $0.15 million and $0.30
million, respectively.

10. COMMITMENTS AND CONTINGENT LIABILITIES

The Company leases facilities and operating equipment from third parties
under operating lease arrangements, certain of which contain renewal or purchase
options. Total charges to income for rent expense aggregated $0.4 million in
1996, $0.9 million in 1997 and $1.8 million in 1998.

Future minimum lease commitments under operating leases in each of the five
years subsequent to December 31, 1998 are $1.1 million in 1999, $1.0 million in
2000, $0.9 million in 2001, $0.8 million in 2002, $0.8 million in 2003 and $3.0
million thereafter.

The Company has employment agreements with two of its executive officers
that provide for severance payments and accelerated vesting of options upon
termination of employment under certain circumstances. The Company's maximum
contingent obligation for severance payments under these agreements in such
event was approximately $1.4 million at December 31, 1998.

The Company is involved in various legal actions and claims arising in the
normal course of business. Based upon its current assessment of the facts, and
the law, management does not believe that the outcome of any such action or
claim will have a material adverse effect upon the consolidated financial
position or results of operations of the Company. However, these actions against
the Company are subject to the uncertainties inherent in any litigation.

AF-14
148
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. MONETIZATION OF SECTION 29 TAX CREDITS

In 1997, the Company entered into a transaction with a financial
institution under which it monetized $43 million of future Section 29 credits
related to its working interests in approximately 1,500 gross wells. In
consideration, the Company received a production payment and a note which
entitles it to all of the cash flow from the properties until approximately 95%
of the expected, pre-tax net present value of the presently projected future
production from the properties has been received, which is expected to occur in
the year 2018. In addition to the note and production payment, the Company
received a fixed cash payment at closing of $7.9 million (recorded as a
reduction to the book value of oil and gas properties) and will receive
quarterly payments equal to a specified percentage of the Section 29 tax credits
generated from the properties through 2002. The Company also retained a
reversionary interest in the properties pursuant to which 100% of the interests
in the properties transferred will revert to the Company when 100% of currently
projected future production from the properties has been realized.

Based on current law, Section 29 tax credits will be available until
December 31, 2002. The Company has the option to repurchase the properties after
December 31, 2002 at the fair market value of the properties at the time of
repurchase less the value of the outstanding note and production payment and the
value of the reversionary interest. The Company has also entered into a
management services agreement with the buyer pursuant to which the Company will
manage and operate the properties on behalf of the buyer.

12. SUBSEQUENT EVENT

On October 13, 1999, The Statoil Group -- Norway ("Statoil") announced
plans to seek a buyer for its U.S. natural gas and electric power production and
marketing unit, Statoil Energy, Inc. ("STEN") in connection with a corporate
restructuring process. The Statoil Group has announced its intentions to market
STEN as an integrated enterprise consisting of STEN's subsidiaries, including
Eastern States, involved in gas production, power production, energy marketing
and energy trading. However, the Statoil Group may determine that the sale of
individual assets or divisions, including Eastern States, is more appropriate.
If such a sale of Statoil Energy or Eastern States occurs, no assurance can be
given that it will not adversely affect the Company. In addition, an employee
retention program has been implemented which will extend through the first
anniversary of the sale date.

13. RESERVE INFORMATION (UNAUDITED)

Costs incurred in the Company's natural gas and oil operations, including
internal capitalization allocations, were as follows (in thousands):

YEAR ENDED DECEMBER 31,
----------------------------
1996 1997 1998
------- -------- -------

Exploration............................................ $ 1,956 $ 3,932 $ 2,772
Development............................................ 13,535 22,743 69,667
Acquisitions
Natural gas and oil properties....................... 33,115 534,198 8,403
Gathering systems.................................... 7,665 32,937 --
Production costs, net of service fees.................. 2,414 6,866 10,089
------- -------- -------
$58,685 $600,676 $90,931
======= ======== =======

Depreciation, depletion and amortization relating to natural gas and oil
operations for the years ended December 31, 1996, 1997, and 1998 was $4.7
million, $18.9 million, and $30.6 million, respectively. Internal costs
capitalized for the years ended December 31, 1996, 1997 and 1998 were $3.0
million, $7.1 million and $14.9 million, respectively.

AF-15
149
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)

The following tables set forth information with respect to the Company's
estimated proved natural gas and oil reserves, all of which are located in the
continental United States. The information has been reviewed by Ryder Scott
Company, L.P., an independent petroleum engineering firm, as of December 31,
1998.

The table of proved natural gas and oil reserves represents estimated
quantities of natural gas, oil and natural gas liquids which geological and
engineering data demonstrate to be recoverable in future years from known
reservoirs under existing economic and operating conditions. The proved reserves
are further classified as developed and undeveloped. The reserves described
below and the related standardized measures of discounted net cash flows are
estimates only and do not purport to reflect realizable values or fair market
values of the Company's reserves. The Company emphasizes that reserve estimates
are inherently imprecise. Substantial revisions to existing reserve estimates
occur periodically due to additional production history from each well,
current-year drilling activity and other new geologic or reserve characteristic
information that may be discovered each year.

The Company's estimates of proved developed and undeveloped reserves of
natural gas (99% in 1998) and oil (1% in 1998) expressed in millions of cubic
feet equivalents (MMcfe) as of December 31, 1996, 1997, 1998, and the change in
its proved reserves are as follows:

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1997 1998
------- --------- ---------

Proved developed and undeveloped reserves
Beginning of year.................................. 82,656 176,673 1,025,315
Production......................................... (6,825) (24,192) (38,514)
Revisions of previous estimates.................... 5,801 (5,521) 150
Acquisitions of reserves in place.................. 64,732 913,104 1,293
Disposition of reserves in place................... (5,336) (51,144) (22,356)
Extensions, discoveries and other revisions........ 35,645 16,395 95,850
------- --------- ---------
End of year........................................ 176,673 1,025,315 1,061,738
======= ========= =========
Proved developed reserves at end of year............. 129,749 715,664 709,305
======= ========= =========

Standardized Measure of Discounted Future Net Cash Flows (in thousands)

DECEMBER 31,
-----------------------------------
1996 1997 1998
--------- ---------- ----------

Future cash flows................................ $ 649,856 $2,670,246 $2,901,515
Future development costs......................... (28,428) (175,215) (195,499)
Future production costs.......................... (125,680) (554,171) (548,361)
Future income tax expense........................ (155,599) (547,697) (632,829)
--------- ---------- ----------
Future net cash flows............................ 340,149 1,393,163 1,524,826
Discount at 10% per annum for timing of cash
flows.......................................... (203,974) (873,454) (986,425)
--------- ---------- ----------
Discounted future net cash flows................. $ 136,175 $ 519,709 $ 538,401
========= ========== ==========

AF-16
150
EASTERN STATES OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1997 1998
-------- --------- --------

Balance, beginning of year.......................... $ 52,071 $ 136,175 $519,709
Sales, net of production costs...................... (16,337) (60,528) (77,983)
Extensions and discoveries, net of production
costs............................................. 47,708 13,162 72,593
Acquisitions of developed reserves in place......... 56,958 466,177 928
Acquisitions of undeveloped reserves in place....... -- 157,903 --
Disposition of reserves in place.................... (5,672) (32,184) (24,826)
Change in sales prices, net of production costs..... 27,458 (68,043) 14,319
Changes in estimated future development costs....... (27) 3,731 (11,761)
Previously estimated development cost incurred
during the year................................... 4,500 7,410 17,617
Revisions of quantity estimates..................... (3,318) (3,376) 4,923
Accretion of discount............................... 6,331 18,333 64,406
Change in income taxes.............................. (36,975) (109,351) 6,388
Changes in production rates and other............... 3,478 (9,700) (47,912)
-------- --------- --------
Balance, end of year................................ $136,175 $ 519,709 $538,401
======== ========= ========

The standardized measure of discounted future net cash flows (discounted at
10%) relating to proved natural gas and oil reserves is prescribed by SFAS
Statement No. 69, "Disclosures About Oil and Gas Producing Activities." The
statement requires measurement of future net cash flows through assignment of a
monetary value to proved reserve quantities and changes therein using a
standardized formula. The amounts shown above were developed as follows:

1. An estimate was made of the quantity of proved reserves and the
future periods in which they are expected to be produced based on
year-end economic conditions.

2. Year-end prices in effect for each respective year were applied to
the estimated quantities of year-end reserves. Prices remained
constant, except in instances where fixed and determinable gas
price escalations are provided by contracts. The average prices
used at December 31, 1996, 1997, and 1998 were $3.68, $2.57, and
$2.71 per Mcf of natural gas and $22.50, $15.00, and $9.00 per
barrel of oil, respectively.

3. The future gross cash inflows were reduced by estimated future
costs of developing and producing the proved reserves and the
estimated effect of future income taxes. The principal sources of
changes in the standardized measure of future net cash flows are
described above.

AF-17
151

EASTERN STATES OIL & GAS, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

ASSETS

DECEMBER 31, JUNE 30,
1998 1999
------------ -----------
(AUDITED) (UNAUDITED)

Current assets
Accounts receivable -- related party...................... $ 28,787 $ 17,048
Accounts receivable -- trade, net......................... 7,732 7,298
Inventories............................................... 1,600 1,633
Prepaid expenses and other................................ 159 143
-------- --------
Total current assets.............................. 38,278 26,122
-------- --------
Property and equipment, net
Natural gas and oil properties (full cost method)......... 559,523 563,767
Gathering systems......................................... 56,088 57,106
Other property and equipment.............................. 4,196 4,428
-------- --------
Total property and equipment...................... 619,807 625,301
-------- --------
Other assets................................................ 248 444
-------- --------
Total assets...................................... $658,333 $651,867
======== ========

LIABILITIES AND STOCKHOLDER'S EQUITY

Current liabilities
Accounts payable.......................................... $ 21,214 $ 9,579
Accrued expenses.......................................... 1,136 991
Accrued severance and property taxes...................... 2,713 2,140
-------- --------
Total current liabilities......................... 25,063 12,710
-------- --------
Deferred income taxes....................................... 926 3,766
Long-term debt.............................................. 505,488 505,488
Intercompany liabilities.................................... 51,974 48,217
Other liabilities........................................... 1,801 2,559
Stockholder's equity
Common stock ($1 par value, 1,000 shares authorized,
issued and outstanding)................................ 1 1
Additional paid-in capital................................ 51,500 51,500
Retained earnings......................................... 21,580 27,626
-------- --------
Total stockholder's equity........................ 73,081 79,127
-------- --------
Total liabilities and stockholder's equity........ $658,333 $651,867
======== ========

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

AF-18
152

EASTERN STATES OIL & GAS, INC.

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)

SIX MONTHS ENDED
JUNE 30,
-----------------
1998 1999
------- -------

Revenue
Natural gas and oil....................................... $50,034 $53,149
Tax credit monetization................................... 4,643 4,574
------- -------
54,677 57,723
------- -------
Costs and expenses
Direct operating costs.................................... 7,927 8,043
Selling, general and administrative....................... 2,249 2,868
Depreciation, depletion and amortization.................. 16,520 16,129
------- -------
26,696 27,040
------- -------
Income from operations...................................... 27,981 30,683
Interest expense............................................ 19,513 21,265
------- -------
Income before income taxes.................................. 8,468 9,418
Income tax expense.......................................... 3,112 3,372
------- -------
Net income.................................................. $ 5,356 $ 6,046
======= =======

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

AF-19
153

EASTERN STATES OIL & GAS, INC.

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

SIX MONTHS ENDED
JUNE 30,
-------------------
1998 1999
-------- --------

Cash flows from operating activities
Net income................................................ $ 5,356 $ 6,046
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion and amortization............... 16,520 16,129
Deferred income tax expense............................ 2,857 2,840
Net changes in working capital
Accounts receivable.................................... 4,943 12,173
Inventories............................................ 820 (33)
Prepaid expenses and other............................. (29) 16
Accounts payable and accrued expenses.................. (8,386) (12,353)
-------- --------
Net cash provided by operating activities................... 22,081 24,818
-------- --------
Cash flows from investing activities
Acquisition of natural gas and oil properties............. (1,695) (140)
Other additions to natural gas and oil properties......... (22,207) (21,458)
Disposition of natural gas and oil properties............. 23,673 --
Other..................................................... (277) 537
-------- --------
Net cash used in investing activities....................... (506) (21,061)
-------- --------
Cash flows from financing activities
Issuance of long-term debt................................ 1,900 --
Intercompany activity..................................... (23,475) (3,757)
-------- --------
Net cash used in financing activities....................... (21,575) (3,757)
-------- --------
Net change in cash and cash equivalents..................... -- --
Cash and cash equivalents
Beginning of year......................................... -- --
-------- --------
End of the year........................................... $ -- $ --
======== ========

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

AF-20
154

EASTERN STATES OIL & GAS, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION

Eastern States Oil & Gas, Inc ("Company") is a wholly-owned subsidiary of
Statoil Energy Holding, Inc. ("SEH") and is engaged in natural gas and oil
exploration and production in the states of Ohio, West Virginia and Kentucky.
SEH is a wholly-owned subsidiary of Statoil Energy, Inc. ("STEN") and holds
STEN's interests in various operating entities engaged in energy related
activities.

The accompanying condensed consolidated financial statements of the Company
have been prepared in accordance with generally accepted accounting principles
for interim financial information and with the instructions for Article 10 of
Regulation S-X. The consolidated balance sheet as of June 30, 1999, the
consolidated statements of operations for the six months ended June 30, 1998 and
1999 and the consolidated statements of cash flows for the six month periods
ended June 30, 1998 and 1999 are unaudited but include all adjustments
(consisting of only normal recurring adjustments) which the Company considers
necessary for a fair presentation of the financial position at such dates and
the operating results and cash flows for those periods. Although the Company
believes that the disclosures in the accompanying consolidated financial
statements are adequate to make the information presented not misleading,
certain information normally included in financial statements and related
footnotes prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to the rules and regulations of the
Securities and Exchange Commission. The December 31, 1998 consolidated balance
sheet data included herein were derived from audited consolidated financial
statements but do not include all disclosures required by generally accepted
accounting principles. The accompanying financial statements should be read in
conjunction with the consolidated financial statements for the year ended
December 31, 1998 and related footnotes as contained within this Form S-1.

The unaudited consolidated financial statements include the accounts of the
Company, its wholly-owned subsidiaries and its proportionate share of the
assets, liabilities, revenue and expenses of various oil and gas development
ventures. All intercompany accounts and transactions have been eliminated.

2. SUBSEQUENT EVENT

On October 13, 1999, The Statoil Group -- Norway ("Statoil") announced
plans to seek a buyer for its U.S. natural gas and electric power production and
marketing unit, Statoil Energy, Inc. ("STEN") in connection with a corporate
restructuring process. The Statoil Group has announced its intentions to market
STEN as an integrated enterprise consisting of STEN's subsidiaries, including
Eastern States, involved in gas production, power production, energy marketing
and energy trading. However, the Statoil Group may determine that the sale of
individual assets or divisions, including Eastern States, is more appropriate.
If such a sale of Statoil Energy or Eastern States occurs, no assurance can be
given that it will not adversely affect the Company.

AF-21
155

EASTERN STATES OIL & GAS, INC.

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The accompanying Unaudited Pro Forma Consolidated Financial Statements of
Eastern States Oil & Gas, Inc. ("the Company") have been prepared by recording
pro forma adjustments to the historical consolidated financial statements of the
Company. The Unaudited Pro Forma Consolidated Balance Sheet as of June 30, 1999
has been prepared as if the Trust Offering, as described in Note 2, was
consummated on June 30, 1999. The Unaudited Pro Forma Consolidated Statements of
Operations for the year ended December 31, 1998 and for the six months ended
June 30, 1999 have been prepared as if the Trust Offering was consummated
immediately prior to January 1, 1998 and January 1, 1999, respectively.

The Unaudited Pro Forma Consolidated Financial Statements are not
necessarily indicative of the financial position or results of operations which
would have occurred had the transactions occurred on the assumed dates.
Additionally, future results may vary significantly from the results reflected
in the Unaudited Pro Forma Consolidated Statements of Operations due to normal
production declines, changes in prices, future transactions and other factors.
These statements should be read in conjunction with the Company's audited
consolidated financial statements and the related notes for the year ended
December 31, 1998, included in this prospectus.

AF-22
156

EASTERN STATES OIL & GAS, INC.

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
JUNE 30, 1999

ASSETS

PRO FORMA ADJUSTMENTS (NOTE 3)
-------------------------------------
TRUST TOTAL
HISTORICAL OFFERING (A) PRO FORMA
---------- ------------ ---------
(IN THOUSANDS)

Current assets
Accounts receivable -- related party...................... $ 17,048 $ 17,048
Accounts receivable -- trade, net......................... 7,298 7,298
Inventories............................................... 1,633 1,633
Prepaid expenses and other................................ 143 143
-------- --------- --------
Total current assets.............................. 26,122 26,122
-------- --------- --------
Property and equipment, net
Natural gas & oil properties (full cost method)........... 563,767 $(127,911) 435,856
Gathering systems......................................... 57,106 57,106
Other property and equipment.............................. 4,428 4,428
-------- --------- --------
Total property and equipment...................... 625,301 (127,911) 497,390
-------- --------- --------
Other assets................................................ 444 444
-------- --------- --------
Total assets...................................... $651,867 $(127,911) $523,956
======== ========= ========

LIABILITIES AND STOCKHOLDER'S EQUITY

Current liabilities
Accounts payable.......................................... $ 9,579 $ 9,579
Accrued expenses.......................................... 991 991
Accrued severance & property taxes........................ 2,140 2,140
-------- --------- --------
Total current liabilities......................... 12,710 12,710
-------- --------- --------
Deferred income taxes....................................... 3,766 3,766
Long-term debt.............................................. 505,488 $(127,911) 377,577
Intercompany liabilities.................................... 48,217 48,217
Other liabilities........................................... 2,559 2,559
Stockholder's equity
Common stock ($1 par value, 1,000 shares authorized, issued
and outstanding).......................................... 1 1
Additional paid-in capital.................................. 51,500 51,500
Retained earnings........................................... 27,626 27,626
-------- --------- --------
Total stockholder's equity........................ 79,127 79,127
-------- --------- --------
Total liabilities and stockholder's equity........ $651,867 $(127,911) $523,956
======== ========= ========

See accompanying notes to pro forma consolidated financial statements.

AF-23
157

EASTERN STATES OIL & GAS, INC.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1998

PRO FORMA ADJUSTMENTS (NOTE 3)
-------------------------------------
TRUST TOTAL
HISTORICAL OFFERING (B) PRO FORMA
---------- ------------ ---------
(IN THOUSANDS)

Revenue
Natural gas and oil....................................... $ 95,315 $(25,246) $70,069
Tax credit monetization................................... 9,355 9,355
-------- -------- -------
104,670 (25,246) 79,424
-------- -------- -------
Costs and expenses
Direct operating costs.................................... 15,950 (5,171) 10,779
Selling, general and administrative....................... 5,462 (1,653) 3,809
Depreciation, depletion and amortization.................. 31,517 (8,560) 22,957
-------- -------- -------
52,929 (15,384) 37,545
-------- -------- -------
Income from operations...................................... 51,741 (9,862) 41,879
Interest expense............................................ 38,952 (10,233) 28,719
-------- -------- -------
Income before income taxes.................................. 12,789 371 13,160
Income tax expense.......................................... 4,443 151 4,594
-------- -------- -------
Net income.................................................. $ 8,346 $ 220 $ 8,566
======== ======== =======

See accompanying notes to pro forma consolidated financial statements.

AF-24
158

EASTERN STATES OIL & GAS, INC.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 1999

PRO FORMA ADJUSTMENTS (NOTE 3)
-------------------------------------
TRUST TOTAL
HISTORICAL OFFERING (B) PRO FORMA
---------- ------------ ---------
(IN THOUSANDS)

Revenue
Natural gas and oil....................................... $53,149 $(10,824) $42,325
Tax credit monetization................................... 4,574 4,574
------- -------- -------
57,723 (10,824) 46,899
------- -------- -------
Costs and expenses
Direct operating costs.................................... 8,043 (2,586) 5,457
Selling, general and administrative....................... 2,868 (826) 2,042
Depreciation, depletion and amortization.................. 16,129 (4,006) 12,123
------- -------- -------
27,040 (7,418) 19,622
------- -------- -------
Income from operations...................................... 30,683 (3,406) 27,277
Interest expense............................................ 21,265 (5,116) 16,149
------- -------- -------
Income before income taxes.................................. 9,418 1,710 11,128
Income tax expense.......................................... 3,372 699 4,071
------- -------- -------
Net income.................................................. $ 6,046 $ 1,011 $ 7,057
======= ======== =======

See accompanying notes to pro forma consolidated financial statements.

AF-25
159

EASTERN STATES OIL & GAS, INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

The accompanying Unaudited Pro Forma Consolidated Balance Sheet at June 30,
1999 has been prepared assuming Eastern States Oil & Gas, Inc. ("the Company")
consummated the sale of 75% of the Appalachian Natural Gas Trust (formerly the
Appalachian Basin Royalty Trust) units to the public ("Trust Offering") on June
30, 1999 (Note 2). The Unaudited Pro Forma Consolidated Statements of Operations
for the year ended December 31, 1998 and the six months ended June 30, 1999 have
been prepared assuming the Company consummated the Trust Offering immediately
prior to January 1, 1998 and January 1, 1999, respectively. The Unaudited Pro
Forma Consolidated Statements of Operations are not necessarily indicative of
the results of operations had the above-described transactions occurred on the
assumed dates.

2. APPALACHIAN NATURAL GAS TRUST OFFERING

The Company formed the Appalachian Natural Gas Trust in August 1999. The
Company plans to sell 7,875,000, or 75%, of the Appalachian Natural Gas Trust
units to the public in October or November 1999. An additional 11.25%, or
1,181,250 units, may be sold pursuant to exercise of the underwriters'
overallotment option. The offering price to the public will be $20.00 per Trust
unit.

3. PRO FORMA ADJUSTMENTS

Pro Forma adjustments necessary to adjust the Consolidated Balance Sheet
and Statements of Operations are as follows:

(a) To record net proceeds of $127,911,000 received by the Company upon
consummation of the Trust Offering, reflecting the sale of 7,875,000
Appalachian Natural Gas Trust units by the Company to the public at a
price of $20.00 per unit, less underwriters' discount, hedging effects
and estimated expenses. This transaction has been reflected as a
reduction of natural gas and oil properties, as it has an immaterial
impact on the Company's depletion rate. All proceeds from the offering
will be used to repay debt to a related party.

(b) To record reduction of revenue and expenses related to the sale of
Appalachian Natural Gas Trust units, assuming the underwriters'
overallotment option is not exercised (Note 2), the reduction in
interest expense attributable to a decrease in long-term debt upon
application of net proceeds of $127,911,000 from the Trust Offering
(Note 3(a)) and the related change in income taxes at the Company's
effective tax rate of 40.85%. Interest expense was determined using the
interest rate of 8% incurred by the Company under its long-term note
payable.

4. PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

Estimated Quantities of Pro Forma Proved Oil and Gas Reserves

Pro forma reserve estimates at June 30, 1999 are based on reports
prepared by management for proved reserves of the Company, using June 30,
1999 prices and costs.

Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which, based on geologic and engineering data, are
estimated to be reasonably recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved
developed reserves are those which are expected to be recovered through
existing wells with existing equipment and operating methods. Because of
inherent uncertainties and the limited nature of reservoir data, such
estimates are subject to change, as additional information becomes
available.

AF-26
160

Pro Forma Proved Oil and Gas reserves at June 30, 1999

OIL (BBLS) GAS (MMCF)
---------- ----------
(IN THOUSANDS)

Proved reserves............................................. 1,859 806,693
===== =======
Proved developed reserves................................... 1,827 480,270
===== =======

Standardized Measure of Discounted Future Net Cash Flows Relating to pro
Forma Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows ("Standardized
Measure") is prepared using assumptions required by the Financial Accounting
Standards Board. Such assumptions include the use of year-end prices for oil and
gas and year-end costs for estimated future development and production
expenditures to produce year-end estimated proved reserves. Discounted future
net cash flows are calculated using a 10% rate.

The Standardized Measure does not represent the Company's estimate of
future net cash flows or the value of proved oil and gas reserves. Probable and
possible reserves, which may become proved in the future, are excluded from the
calculations. Furthermore, year-end prices, used to determine the standardized
measure of discounted cash flows, are influenced by seasonal demand other
factors and may not be the most representative in estimating future revenues or
reserve data.

Pro Forma Standardized Measure of Discounted Future Net Cash Flows (in
thousands) at:

DECEMBER 31, JUNE 30,
1998 1999
------------ ----------

Future cash flows........................................... $2,273,567 $1,979,654
Future production costs..................................... (423,922) (398,211)
Future development costs.................................... (181,308) (180,535)
---------- ----------
Future net cash inflows before income tax................... 1,668,337 1,400,908
Future income tax expense................................... (489,314) (258,286)
---------- ----------
Future net cash flows....................................... 1,179,023 1,142,622
Discount at 10% per annum for timing of cash flows.......... (761,617) (784,108)
---------- ----------
Discounted future net cash flows............................ $ 417,406 $ 358,514
========== ==========

AF-27
161

REPORT OF INDEPENDENT AUDITORS

Board of Directors and Stockholder
Eastern States Oil & Gas, Inc.

We have audited the accompanying consolidated income statement and cash
flows for the domestic operations of Blazer Energy Corp. and subsidiary
(formerly Ashland Exploration, Inc.) for the year ended September 30, 1996.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audit.

We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated results of domestic operations and
cash flows for Blazer Energy Corp. and subsidiary for the year ended September
30, 1996, in conformity with generally accepted accounting principles.

ERNST & YOUNG LLP

Vienna, Virginia
August 23, 1999

AF-28
162

DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

CONSOLIDATED INCOME STATEMENT
YEAR ENDED SEPTEMBER 30, 1996
(IN THOUSANDS)

Revenues:
Sales and operating revenues:
Natural gas............................................ $ 94,750
Crude oil.............................................. 3,759
Columbia Gas settlement (Note 5).......................... 73,139
Other (Note 6)............................................ 1,671
--------
173,319
--------
Cost and expenses:
Operating expenses........................................ 32,642
NORM reclamation/litigation (Note 3)...................... 3,049
Depreciation, depletion and amortization (Note 1)......... 28,921
General and administrative expenses (Note 7).............. 15,658
Exploration costs, including dry holes.................... 11,204
--------
91,474
--------
Operating income............................................ 81,845
Interest expense............................................ 195
--------
Income before income taxes.................................. 81,650
Income tax expense (Note 2)................................. 19,132
--------
Net income.................................................. $ 62,518
========

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

AF-29
163

DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED SEPTEMBER 30, 1996
(IN THOUSANDS)

Cash flows from operating activities
Net income................................................ $ 62,518
Adjustments to reconcile income to net cash provided by
operating activities:
Depreciation, depletion and amortization............... 28,921
Impairment of undeveloped leaseholds................... 2,128
Deferred income taxes.................................. 4,438
Changes in operating assets and liabilities:
Accounts receivable.................................... (4,288)
Inventories............................................ 300
Prepaids and other current assets...................... (766)
Trade accounts payable................................. 25,840
Accrued liabilities.................................... 2,438
Other.................................................. (1,961)
--------
Net cash provided by operating activities................... 119,568
--------
Cash flows from investing activities
Property, plant and equipment:
Additions.............................................. (45,091)
Property disposals..................................... 2,149
--------
Net cash used in investing activities....................... (42,942)
--------
Increase in net obligations with affiliated Companies....... $ 76,626
========

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

AF-30
164

DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1996

1. SIGNIFICANT ACCOUNTING POLICIES

Background

Blazer Energy Corp. and subsidiary (formerly Ashland Exploration, Inc.)
("Company") operated both domestic and international exploration and production
activities. Immediately prior to the acquisition of the Company by a subsidiary
of Statoil Energy, Inc. (see Note 10), Ashland Inc. (parent company of Blazer
Energy Corp.) removed all international exploration and production operations of
the Company. The accompanying financial statements reflect all domestic
exploration and production operations. The Company is engaged in the exploration
for and the development, production, acquisition and marketing of natural gas
and oil in the United States.

Consolidation

The financial statements include the domestic accounts of Blazer Energy
Corp. and subsidiary. Significant intercompany accounts and transactions have
been eliminated in consolidation. Consistent with industry practice, the Company
utilizes pro rata consolidation to account for its investment in oil and gas
ventures.

Risk and uncertainties

The preparation of the Company's consolidated financial statements in
conformity with generally accepted accounting principles requires the Company's
management to make estimates and assumptions that affect the reported amounts of
revenues and expenses. Actual results could differ from the estimates and
assumptions used.

Inventories

Crude oil inventories are stated at current market value. Materials and
supplies inventories are stated at the lower of cost or market.

Property, plant and equipment

The successful efforts method of accounting is followed for costs incurred
in oil and gas exploration and development activities. Property acquisition
costs and exploratory drilling costs for oil and gas properties are initially
capitalized. If and when exploratory wells are determined to be nonproductive,
the related costs are charged to expense. Other exploration costs, including
geological, geophysical and lease rentals, are charged to expense as incurred.

When a property is determined to contain proved reserves, property
acquisition costs and related exploratory drilling costs are transferred to
producing properties. Depreciation, depletion and amortization of producing
properties are computed separately on a field basis using the
units-of-production method.

Significant unproved properties are periodically evaluated and provision
made for impairment individually. Insignificant properties are amortized to
provide for estimated impairment.

Environmental Costs

Accruals for environmental costs are recognized when it is probable that a
liability has been incurred and the amount of that liability can be reasonably
estimated. Such costs are charged to expense if they are related to the
remediation of conditions caused by past operations, or are not expected to
mitigate or prevent contamination from future operations. Accruals are recorded
at undiscounted amounts based on

AF-31
165
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

experience, assessments and current technology and are regularly adjusted as
environmental assessments and remediation efforts proceed.

Natural Gas Revenues

Natural gas revenues generally are recorded using the sales method, whereby
the Company recognizes natural gas revenues based on the amount of gas sold to
purchasers on its behalf. As of September 30, 1996, the Company did not have any
material gas imbalances.

Crude Oil Revenues

Crude oil revenue is recognized as produced.

Dismantlement, Removal and Restoration Costs

The estimated costs, net of salvage values, of dismantling and removing
major facilities, including necessary site restoration, are accrued using the
units-of-production method. In the case of facilities where such costs are not
expected to be significant, the net cost is accrued when operations cease.

Income Taxes

The consolidated domestic provision was computed on the basis of a separate
return.

Hedging Activities

The Company selectively uses futures contracts and swaps to reduce price
volatility and lock in favorable sales prices for future production of natural
gas and crude oil. Gains and losses on futures contracts and swaps are deferred
until the related gas or oil production has been produced or delivered. As a
result, gains and losses are generally offset by similar changes in the price of
natural gas and crude oil. While these instruments are intended to reduce the
Company's exposure to declines in the market price of natural gas and crude oil,
they may also limit the Company's gain from increases in the market price of
natural gas and crude oil.

The futures contracts have settlement guaranteed by the New York Mercantile
Exchange ("NYMEX") and have nominal credit risk. The swap agreements are with
third parties and expose the Company to credit risk to the extent the third
parties are unable to meet their monthly settlement commitment to the Company.

2. INCOME TAXES

A summary of the provision for income tax expense follows:

YEAR ENDED
SEPTEMBER 30,
1996
--------------
(IN THOUSANDS)

Current tax expense.................................... $14,694
Deferred tax expense................................... 4,438
-------
$19,132
=======

AF-32
166
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The difference between the statutory rate and the Company's effective
income tax rate is reconciled as follows:

YEAR ENDED
SEPTEMBER 30,
1996
--------------
(IN THOUSANDS)

Income tax computed at statutory rates................. $28,578
Section 29 tax credits................................. (10,509)
Adjustment to prior year's tax......................... 537
State tax, net of federal tax.......................... 137
Other.................................................. 389
-------
$19,132
=======

3. COMMITMENTS AND CONTINGENCIES

The Company is subject to various federal, state and local environmental
laws and regulations, which require remediation efforts at multiple locations,
including operating facilities and previously owned or operated facilities.
Environmental reserves are subject to considerable uncertainties that affect the
Company's ability to estimate its share of the ultimate costs of required
remediation efforts. Such uncertainties involve the nature and extent of
contamination at each site, the extent of required cleanup efforts under
existing environmental regulations, widely varying costs of alternate cleanup
methods, changes in environmental regulations, the potential effect of
continuing improvements in remediation technology and the number and financial
strength of other potentially responsible parties at multiparty sites. As a
result, charges to income for environmental liabilities could have a material
effect on results of operations in a particular quarter or fiscal year as
assessments and remediation efforts proceed, revised estimates are made based on
current information or as new remediation sites are identified.

During 1996, the U.S. Environmental Protection Agency and the state of
Kentucky approved the Company's plan of reclamation (including disposal off
site) of naturally occurring radioactive material ("NORM") from the Martha oil
field in Kentucky. The Company's independent contractor began implementing the
NORM reclamation work in September 1996.

In addition to environmental matters, the Company is party to numerous
claims and lawsuits. While these actions are being contested, the outcome of
individual matters is not predictable with assurance. Although any actual
liability is not determinable as of September 30, 1996, the Company believes
that any liability resulting from these matters, after taking into consideration
Ashland's insurance coverages should not have a material adverse effect on the
Company's consolidated financial position.

4. EMPLOYEES' PENSION AND RETIREMENT BENEFITS

Ashland sponsors pension plans that cover substantially all employees,
other than union employees covered by multiemployer pension plans under
collective bargaining agreements. Benefits under Ashland's plans generally are
based on employees' years of service and compensation during the years
immediately preceding their retirement. For certain plans, such benefits are
expected to come in part from one-half of employees' leveraged employee stock
ownership plan ("LESOP") accounts. Ashland determines the level of contributions
to the pension plans annually and contributes amounts within allowable
limitations imposed by Internal Revenue Service regulations. Ashland contributed
the maximum tax-deductible contributions to its pension plans during the last
three years. A discount rate of 8% and an assumed rate of salary increases of 5%
were used in determining the actuarial present value of projected benefit
obligations at September 30, 1996. The Company's expense related to pension and
the LESOP amounted to $1,512,000 in 1996.

AF-33
167
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

5. COLUMBIA GAS SETTLEMENT

During 1995, the Company entered into a settlement agreement with Columbia
Gas Transmission ("Columbia") to resolve claims involving natural gas sales
contracts that were abrogated by Columbia in 1991. The agreement provided for a
$78,500,000 payment to the Company, of which 5% was withheld by Columbia to be
used to potentially satisfy the claims of nonsettling producers. The Company
received the proceeds net of expenses under this agreement in 1996, which
resulted in operating income of $73,139,000. In the event that any portion of
the amount withheld by Columbia is not used to satisfy such nonsettling claims,
the Company and Ashland have agreed that such amount will be paid to Ashland.

6. OTHER REVENUES

The Company purchases third-party natural gas for resale and delivery into
major interstate pipelines. Revenue from these purchases and resales were
$500,000 in 1996.

7. RELATED PARTY TRANSACTIONS

The Company sells natural gas production to Ashland Petroleum Company, a
wholly owned subsidiary of Ashland. Sales to Ashland Petroleum Company were
$2,700,000 for the fiscal year ending 1996.

Certain administrative services are provided to the Company by Ashland. For
these services, the Company receives an allocation of Ashland's general and
administrative expenses which amounted to $2,326,000 in 1996. These services
include, among others, insurance administration and certain tax and legal
administrative activities. It is Ashland's policy to charge these expenses and
all other central administrative costs on the basis of direct usage when
identifiable. Management of the Company has determined that this method is
reasonable.

8. LEASES AND OTHER COMMITMENTS

The Company is a lessee in noncancelable leasing agreements for office
buildings and other equipment and properties which expire at various dates.
Rental expense under operating leases was $5,900,000 in 1996. Future minimum
rental payments (which escalate over time) at September 30, 1996 follow (in
thousands):

1997....................................................... $1,004
1998....................................................... 950
1999....................................................... 944
2000....................................................... 1,072
2001....................................................... 1,048
Thereafter................................................. 3,104

9. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and
Gas Reserves

The following tables summarize discounted future net cash flows and changes
in such flows in accordance with Statement of Financial Accounting Standards
Board No. 69, ("SFAS 69"), Disclosures About Oil and Gas Producing Activities.
Under the guidelines of SFAS 69, estimated future cash flows are determined
based on current prices for crude oil and natural gas, estimated production of
proved crude oil and natural gas reserves, estimated future production and
development costs of those reserves based on current costs and economic
conditions and estimated future income taxes based on taxing arrangements in
effect at year-end which include allocation of the full tax benefit of Section
29 tax credits. Such cash flows are then discounted using the prescribed 10%
rate.

AF-34
168
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) -- (CONTINUED)

Many other assumptions could have been made which may have resulted in
significantly different estimates. The Company does not rely upon these
estimates in making investment and operating decisions. Furthermore, the Company
does not represent that such estimates are indicative of its expected future
cash flows or the current value of its reserves. Since gas prices utilized in
deriving these estimates are based on conditions that existed at September 30
and are usually different than prices that exist at December 31 due to seasonal
fluctuations in the natural gas market, the estimates may not be comparable to
those of other companies with different fiscal years. Prices can also vary
significantly at the same point in time from year to year due to a variety of
factors. The average gas price used in the discounted future net cash flows
calculations was based on $1.85 per MMBtu for 1996.

Discounted Future Net Cash Flows

SEPTEMBER 30,
1996
-------------
(IN MILLIONS)

Future cash inflows.................................... $1,273
Future production (lifting) costs...................... (509)
Future development costs............................... (55)
Future income taxes.................................... (116)
------
593
Annual 10% discount.................................... (304)
------
Standardized measure of discounted future net cash
flows................................................ $ 289
======

] Changes in Discounted Future Net Cash Flows

YEAR ENDED
SEPTEMBER 30,
1996
-------------
(IN MILLIONS)

Net change due to extensions and discoveries............ $ 27
Sales of oil and gas produced -- net of
production (lifting) costs............................ (85)
Changes in prices....................................... 60
Previously estimated development costs incurred......... 22
Net change due to revisions of previous estimates of
reserves.............................................. 4
Purchase (net of sales) of reserves in place............ 1
Accretion of 10% discount............................... 25
Other -- net(1)......................................... 10
Net change in income taxes.............................. (27)
----
37
Discounted future net cash flows at beginning of year... 252
----
Discounted future net cash flows at end of year......... $289
====

- ---------------

(1) Includes changes in future production and development costs and changes in
the timing of future production.

AF-35
169
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) -- (CONTINUED)

Crude Oil and Natural Gas Reserves, Revenues and Costs

The following tables summarize the Company's crude oil and natural gas
reserves. Crude oil and natural gas reserves are reported net of royalties and
interests owned by others.

Reserves reported in the table are estimated and are subject to future
revisions. Since October 1, 1995, no estimates of the Company's total proved net
oil or gas reserves have been filed or included in reports to any federal
authority or agency other than the Securities and Exchange Commission (the
"Commission"). Crude oil reserves of 1.6 MMBbls at September 30, 1996 are as
estimated by Netherland Sewell.

Crude Oil and Natural Gas Reserves

YEAR ENDED
SEPTEMBER 30,
1996
-------------

Crude Oil Reserves (Mmbbls)
Proved developed and undeveloped reserves:
Beginning of year.................................... 1.3
Revisions of previous estimates...................... 0.4
Extensions and discoveries........................... --
Production........................................... (0.2)
Net purchases of reserves in place................... 0.1
----
End of year.......................................... 1.6
====
Proved developed reserves at beginning of year......... 1.3
Proved developed reserves at end of year............... 1.6

YEAR ENDED
SEPTEMBER 30,
1996
-------------

Natural Gas Reserves (BCF)
Proved developed and undeveloped reserves:
Beginning of year.................................... 507.4
Revisions of previous estimates...................... 37.6
Extensions and discoveries........................... 70.0
Production........................................... (39.7)
Purchase (net of sales) of reserves in place......... 1.6
-----
End of year.......................................... 576.9
=====
Proved developed reserves at beginning of year......... 427.3
Proved developed reserves at end of year............... 477.0

Net Oil and Gas Production

The following table summarizes net oil and gas production (net after
royalty) for the fiscal year ended September 30, 1996.

1996
----

Net natural gas production (MMcf per day)................... 109
Net crude oil production (Bbls per day)..................... 564

AF-36
170
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) -- (CONTINUED)

Average Sales Price and Production Cost

The Company's average sales price per unit and production cost per unit for
crude oil and natural gas for the fiscal year ended September 30, 1996 is set
forth in the table below.

1996
------

Average sales prices -- natural gas (per Mcf)............... $ 2.39
Average sales prices -- crude oil (per Bbl)................. $18.22
Average production cost (per Mcfe)(1)....................... $ 0.47

- ---------------

(1) Equivalents computed on a six Mcf to one Bbl ratio.

Gross and Net Productive Wells

The following table sets forth the Company's gross and net productive
wells.

SEPTEMBER 30,
1996
-------------
GROSS NET
----- -----

Productive wells -- Gas............................... 4,211 3,836
Productive wells -- Oil............................... 36 22

These wells include 317 gross wells and 279 net wells at September 30,
1996, which have multiple completions.

Total Gross and Net Oil and Gas Producing and Undeveloped Acreage

The Company's major interests consist of producing and nonproducing working
interests located in the Appalachian and Gulf Coast areas, as well as royalty
interests located primarily in the Southwest and Midcontinent areas of the
United States. The following table sets forth the Company's total gross and net
oil and gas producing and undeveloped acreage:

GROSS NET GROSS NET
PRODUCING PRODUCING UNDEVELOPED UNDEVELOPED
ACREAGE ACREAGE ACREAGE ACREAGE
- --------- --------- ----------- -----------
(IN THOUSANDS)

1,263 936 748 410

Net Productive and Dry Wells Drilled

The Company's net productive and dry wells drilled during the fiscal year
ended September 30, 1996 are set forth below.

1996
----

Net exploratory wells drilled
Net productive wells...................................... 1
Net dry wells............................................. 1
----
Total............................................. 2
====
Net development wells drilled:
Net productive wells...................................... 79
Net dry wells............................................. --

AF-37
171
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

10. SUBSEQUENT EVENT

On July 1, 1997, a subsidiary of Statoil Energy, Inc. ("STEN") entered into
a Stock Purchase Agreement to acquire the domestic operations of Blazer Energy
Corp. for a purchase price of $567.1 million. Items excluded from this
transaction include the Martha Oil Field in Kentucky, including related
environmental obligations, insurance policies, office facilities and leases,
certain fee interests in land and any potential additional recovery related to
the Columbia Gas settlement (See Note 5). Pursuant to this agreement, Ashland
agreed to indemnify STEN from and against losses resulting from certain other
environmental claims and litigation.

AF-38
172

DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

UNAUDITED CONSOLIDATED INCOME STATEMENT
NINE MONTHS ENDED JUNE 30, 1997
(IN THOUSANDS)

(UNAUDITED)
-----------

Revenues:
Sales and operating revenues
Natural gas............................................ $90,850
Crude oil.............................................. 2,699
Other..................................................... 1,499
-------
95,048
-------
Cost and expenses:
Operating expenses........................................ 26,771
NORM reclamation/litigation (Note 2)...................... 7,525
Depreciation, depletion and amortization.................. 27,999
General and administrative expenses....................... 11,341
Exploration costs, including dry holes.................... 3,850
-------
77,486
-------
Operating income............................................ 17,562
Interest expense............................................ 139
-------
Income before income taxes.................................. 17,423
Income tax benefit (Note 3)................................. (413)
-------
Net income.................................................. $17,836
=======

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

AF-39
173

DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE NINE MONTHS ENDED JUNE 30, 1997
(IN THOUSANDS)

(UNAUDITED)
-----------

Cash flows from operating activities
Net income................................................ $ 17,836
Adjustments to reconcile income to net cash provided by
operating activities:
Depreciation, depletion and amortization............... 27,999
Gain on sale of operations............................. (208)
Deferred income taxes.................................. 6,763
Other non-cash items................................... 633
Change in operating assets and liabilities:
Accounts receivable.................................. 965
Inventories.......................................... (1,516)
Prepaids and other current assets.................... (5,533)
Trade accounts payable............................... (21,088)
Other................................................ (5,348)
--------
Net cash provided by operating activities................... 20,503
--------
Cash flows from investing activities
Property, plant and equipment:
Additions.............................................. (23,713)
Proceeds from sale or restructuring of operations...... 1,166
Property disposals..................................... 214
--------
Net cash used in investing activities....................... (22,333)
--------
Cash flows from financing activities
Investment in subsidiary.................................. (11,142)
Intercompany dividends.................................... (56,138)
--------
Net cash used in financing activities....................... (67,280)
--------
Decrease in net obligations with affiliated Companies....... $(69,110)
========

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

AF-40
174

DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION

Blazer Energy Corp. and subsidiary (formerly Ashland Exploration, Inc.)
("Company") operated both domestic and international exploration and production
operations. Immediately prior to the acquisition of the Company by a subsidiary
of Statoil Energy, Inc. (See Note 4), Ashland Inc. (parent company of Blazer
Energy Corp.) removed all international exploration and production operations of
the Company. The accompanying financial statements reflect all domestic
exploration and production operations. The Company is engaged in the exploration
for and the development, production, acquisition and marketing of natural gas
and oil in the United States.

The financial statements include only the domestic accounts of the Company
and its subsidiary. Significant intercompany accounts and transactions have been
eliminated in consolidation. Consistent with industry practice, the Company
utilizes pro rata consolidation to account for its investment in oil and gas
ventures.

The accompanying condensed consolidated financial statements have been
prepared in accordance with generally accepted accounting principles for interim
financial information and with the instructions for Article 10 of Regulation
S-X. The consolidated income statement for the nine months ended June 30, 1997,
and the consolidated statement of cash flows for the nine month period ended
June 30, 1997, are unaudited but include all adjustments (consisting of only
normal recurring adjustments) which the Company considers necessary for a fair
presentation of the operating results and cash flows for this period. Although
the Company believes that the disclosure in the accompanying consolidated
financial statements is adequate to make the information presented not
misleading, certain information normally included in financial statements and
related footnotes prepared in accordance with generally accepted accounting
principles have been condensed or omitted pursuant to the rules and regulations
of the Securities and Exchange Commission. The accompanying financial statements
should be read in conjunction with the consolidated financial statements for the
year ended September 30, 1996 and related footnotes as contained elsewhere
herein.

2. NORM RECLAMATION AND RELATED LIABILITIES

3. INCOME TAXES

Income tax benefit has been computed on an interim basis based on the
estimated effective rate for the entire year.

4. SUBSEQUENT EVENT

On July 1, 1997, a subsidiary of Statoil Energy, Inc. ("STEN") entered into
a Stock Purchase Agreement to acquire the domestic operations of Blazer Energy
Corp. for a purchase price of $567.1 million. Items excluded from this
transaction include the Martha Oil Field in Kentucky, including related
environmental obligations, insurance policies, office facilities and leases,
certain fee interests in land and any potential additional recovery related to
the Columbia Gas settlement. Pursuant to this agreement, Ashland agreed to
indemnify STEN from and against losses resulting from certain other
environmental claims and litigation.

AF-41
175
EXHIBIT A

[RYDER SCOTT LETTERHEAD]

October 1, 1999

Eastern States Oil & Gas, Inc.
2800 Eisenhower Avenue, Suite 300
Alexandria, Virginia 22314

Gentlemen:

At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of the Underlying Properties Relating to the Appalachian Natural Gas Trust as of
August 31, 1999. The subject properties are located in the states of Kentucky
and West Virginia. The income data were estimated using the Securities and
Exchange Commission (SEC) guidelines for future price and cost parameters.

The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. August 1999 hydrocarbon prices were used in
the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from August 1999 prices. Therefore, volumes
of reserves actually recovered and amounts of income actually received may
differ significantly from the estimated quantities presented in this report. The
results of this study are summarized below.

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
APPALACHIAN NATURAL GAS TRUST
(UNDERLYING PROPERTIES)
As of August 31, 1999

PROVED
--------------------------------------------------------------
DEVELOPED
----------------------------
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL PROVED
------------ ------------- -------------- --------------

NET REMAINING RESERVES
Gas -- MMCF..................... 328,993 588 436,533 766,114
Oil/Condensate -- Barrels....... 259,592 0 0 259,592
INCOME DATA
Future Gross Revenue............ $909,979,004 $1,626,303 $1,218,019,967 $2,129,625,274
Deductions...................... 189,718,479 409,482 468,549,504 658,677,465
------------ ---------- -------------- --------------
Future Net Income (FNI)......... $720,260,525 $1,216,821 $ 749,470,463 $1,470,947,809
Discounted FNI @ 10%............ $264,475,306 $ 385,862 $ 102,416,215 $ 367,277,383

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of 60 degrees Fahrenheit and 14.73 psia.

XA-1
176
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 2

The future gross revenue is before the deduction of production taxes. In
addition, deductions are comprised of the normal direct costs of operating the
wells, recompletion costs, and development costs. Ad valorem taxes have been
included with production tax calculations. The future net income is before the
deduction of state and federal income taxes and general administrative overhead
and does not include any adjustment for cash on hand or undistributed income. No
attempt was made to quantify or otherwise account for any accumulated gas
production imbalances that may exist. Gas reserves account for approximately
99.8 percent and liquid hydrocarbon reserves account for the remaining 0.2
percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded annually.

RESERVES INCLUDED IN THIS REPORT

The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10(a) as
clarified by subsequent Commission Staff Accounting Bulletins. The definitions
of proved reserves are included under the tab "Reserve Definitions and Pricing
Assumptions" in this report.

The proved developed non-producing reserves included herein are comprised
of behind pipe and shut-in categories. The various reserve status categories are
defined under the tab "Reserve Definitions and Pricing Assumptions" in this
report.

ESTIMATES OF RESERVES

Reserves were estimated by decline curve analysis where sufficient
production history was available. In those cases where sufficient production
history was not available, analogy to offset wells was utilized. Due to the low
permeability of the producing formations, other methods such as material balance
and volumetric methods are inappropriate for determining reserves.

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,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.

FUTURE PRODUCTION RATES

Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for the
effects of curtailment where appropriate, until a decline in ability to produce
was anticipated. An estimated rate of decline was then applied to depletion of
the reserves. If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
Eastern States Oil & Gas, Inc. (ESOG).

The future production rates from wells now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.

XA-2
177
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 3

HYDROCARBON PRICES

ESOG furnished us with prices in effect at August 31, 1999 and these prices
were held constant until depletion of the properties. In accordance with
Securities and Exchange Commission guidelines, changes in liquid and gas prices
subsequent to August 31, 1999 were not taken into account in this report. Future
prices used in this report are discussed in more detail under the tab "Reserve
Definitions and Pricing Assumptions" in this report.

COSTS

Operating costs furnished by ESOG were held constant throughout the life of
the properties, except where changes were known and determinable. These changes
include a two-tier cost structure based upon ESOG's actual operating experience
and practices. ESOG's costs are directly proportional to the level of monitoring
provided by field personnel. Since high rate wells are monitored more closely
than low rate wells, high rate wells have been assigned a higher proportion of
the average operating cost. As a well's production drops below a predetermined
threshold limit (5 MCFD), field personnel reduce the level of monitoring
provided to the well, reducing the well's operating costs, and establishing the
two-tier structure as shown below.

TIER 1 TIER 2
DISTRICT $/WELL/MO $/WELL/MO
-------- --------- ---------

Brenton...................................... 138 32
Madison...................................... 144 33
Weston....................................... 151 35
Pikeville.................................... 138 32

An exception to the above are all undeveloped locations which were assigned
$100 per well per month until depletion of the property.

Development costs were furnished to us by ESOG and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. This study does not consider the salvage value of the lease equipment
or the abandonment cost of the subject wells.

GENERAL

While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.

The estimates of reserves presented herein were based upon a detailed study
of the properties in which ESOG owns an interest; however, we have not made any
field examination of the properties. No consideration was given in this report
to potential environmental liabilities which may exist nor were any costs
included for potential liability to restore and clean up damages, if any, caused
by past operating practices. ESOG has informed us that they have furnished us
all of the accounts, records, geological and engineering data, and reports and
other data required for this investigation. The ownership interests, prices, and
other factual data furnished by ESOG were accepted without independent
verification. The estimates presented in this report are based on data available
through March 1999.

Neither we nor any of our employees have 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 income for the subject
properties.

XA-3
178
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 4

This report was prepared for the exclusive use and sole benefit of Eastern
States Oil & Gas, Inc. The data, work papers, and maps used in this report are
available for examination by authorized parties in our offices. Please contact
us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

/s/ DON P. GRIFFIN
--------------------
Don P. Griffin, P.E.
Vice President

XA-4
179

DEFINITIONS OF RESERVES

PROVED RESERVES (SEC DEFINITION)

Proved reserves of crude oil, condensate, natural gas, and 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 operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalation based on
future conditions.

Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. In certain instances,
proved reserves are 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.

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.

Proved natural gas reserves are comprised 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 and
are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage.

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 become available.

XA-5
180

RESERVE STATUS CATEGORIES (SEC)

Reserve status categories define the development and producing status of
wells and/or reservoirs.

PROVED DEVELOPED

Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.

Developed reserves may be subcategorized as producing or non-producing
using the SPE/WPC Definitions:

Producing

Reserves sub-categorized as producing are expected to be recovered
from completion intervals which are open and producing at the time of the
estimate. Improved recovery reserves are considered producing only after
the improved recovery project is in operation.

Non-Producing

Reserves sub-categorized as non-producing include shut-in and behind
pipe reserves. Shut-in reserves are expected to be recovered from (1)
completion intervals which are open at the time of the estimate but which
have not started producing, (2) wells which were shut-in awaiting pipeline
connections or as a result of a market interruption, or (3) wells not
capable of production for mechanical reasons. Behind pipe reserves are
expected to be recovered from zones in existing wells, which will require
additional completion work or future recompletion prior to the start of
production.

PROVED UNDEVELOPED

Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Estimates for proved undeveloped reserves are attributable to any
acreage for which an application of fluid injection or other improved technique
is contemplated, only when such techniques have been proved effective by actual
tests in the area and in the same reservoir.

XA-6
181

HYDROCARBON PRICING PARAMETERS

SECURITIES AND EXCHANGE COMMISSION PARAMETERS

GAS

ESOG furnished us with gas prices in effect at August 31, 1999 as shown
below.

DEVELOPED UNDEVELOPED
DISTRICT $/MCF $/MCF
- -------- --------- -----------

Brenton....................................... 2.756 2.803
Madison....................................... 2.515 2.562
Weston........................................ 2.917 2.964
Pikeville..................................... 2.840 2.887

Gas prices for undeveloped properties assume that incremental gathering and
compression charges will be lower than developed properties due to synergies in
utilizing existing gathering capacity. This results in an effective higher gas
price.

OIL AND CONDENSATE

ESOG furnished us with oil and condensate prices in effect at August 31,
1999 of $18.75 per barrel, and these prices were held constant to depletion of
the properties. In accordance with Securities and Exchange Commission
guidelines, changes in liquid prices subsequent to August 31, 1999 were not
considered in this report.

XA-7
182
EXHIBIT B

[RYDER SCOTT LETTERHEAD]

October 1, 1999

Eastern States Oil & Gas, Inc.
2800 Eisenhower Avenue, Suite 300
Alexandria, Virginia 22314

Gentlemen:

At your request, we have prepared an estimate of the reserves, future
production, and income attributable to the Net Profits Interest Relating to the
Appalachian Natural Gas Trust as of August 31, 1999. The subject properties are
located in the states of Kentucky and West Virginia. The income data were
estimated using the Securities and Exchange Commission (SEC) guidelines for
future price and cost parameters.

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
APPALACHIAN NATURAL GAS TRUST
(NET PROFITS INTEREST)
As of August 31, 1999

PROVED
------------------------------------------------------------
DEVELOPED
----------------------------- TOTAL
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
------------ ------------- ----------- ------------

NET REMAINING RESERVES
Gas -- MMCF...................... 209,642 376 29,083 239,101
Oil/Condensate-Barrels........... 170,541 0 0 170,541
INCOME DATA
Future Gross Revenue............. $551,317,578 $987,650 $75,944,127 $628,249,355
Deductions....................... 44,788,484 80,743 6,173,188 51,042,415
------------ -------- ----------- ------------
Future Net Income (FNI).......... $506,529,094 $906,907 $69,770,939 $577,206,940
Discounted FNI @ 10%............. $191,692,164 $279,177 $ 8,448,469 $200,419,810

XB-1
183
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 2

The Net Profits Interest (NPI) presented herein is based upon the future
net income (FNI) of the Underlying Properties with adjusted prices and costs.
The results of these adjustments to the Underlying Properties are summarized
below.

APPALACHIAN NATURAL GAS TRUST
(ADJUSTED UNDERLYING PROPERTIES)
As of August 31, 1999

PROVED
--------------------------------------------------------------
DEVELOPED
---------------------------- TOTAL
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
------------ ------------- -------------- --------------

NET REMAINING RESERVES
Gas -- MMCF........................ 327,741 588 436,533 764,862
Oil/Condensate -- Barrels.......... 259,486 0 0 259,486
INCOME DATA
Future Gross Revenue............... $861,796,470 $1,545,534 $1,137,697,964 $2,001,039,968
Deductions......................... 228,634,858 411,901 439,988,603 669,035,362
------------ ---------- -------------- --------------
Future Net Income (FNI)............ $633,161,612 $1,133,633 $ 697,709,361 $1,332,004,606
Discounted FNI @ 10%............... $239,615,162 $ 348,972 $ 84,484,734 $ 324,448,868

The NPI for developed and undeveloped properties has been taken as 80
percent and 10 percent of the FNI of the developed and undeveloped properties as
found in the Adjusted Underlying Properties, respectively. Utilizing these
fractional FNIs, equivalent net reserves and production were back-calculated
assuming a royalty ownership. Therefore, no deductions other than production
taxes are shown in the NPI presentation.

The deductions for Adjusted Underlying Properties are comprised of
production taxes and the normal direct costs of operating the wells,
recompletion costs, and development costs. Ad valorem taxes have been included
with production tax calculations. The future net income is before the deduction
of state and federal income taxes and general administrative overhead and does
not include any adjustment for cash on hand or undistributed income. No attempt
was made to quantify or otherwise account for any accumulated gas production
imbalances that may exist.

The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded annually.

RESERVES INCLUDED IN THIS REPORT

ESTIMATES OF RESERVES

XB-2
184
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 3

to the low permeability of the producing formations, other methods such as
material balance and volumetric methods are inappropriate for determining
reserves.

FUTURE PRODUCTION RATES

HYDROCARBON PRICES

COSTS

TIER 1 TIER 2
DISTRICT $/WELL/MO $/WELL/MO
- -------- --------- ---------

Brenton...................................... 170 70
Madison...................................... 170 70
Weston....................................... 170 70
Pikeville.................................... 170 70

XB-3
185
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 4

GENERAL

Very truly yours,

RYDER SCOTT COMPANY, L.P.

/s/ DON P. GRIFFIN
--------------------
Don P. Griffin, P.E.
Vice President

XB-4
186

DEFINITIONS OF RESERVES

PROVED RESERVES (SEC DEFINITION)

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 become available.

XB-5
187

RESERVE STATUS CATEGORIES (SEC)

Reserve status categories define the development and producing status of
wells and/or reservoirs.

PROVED DEVELOPED

Developed reserves may be subcategorized as producing or non-producing
using the SPE/WPC Definitions:

Producing

Non-Producing

PROVED UNDEVELOPED

XB-6
188

HYDROCARBON PRICING PARAMETERS

SECURITIES AND EXCHANGE COMMISSION PARAMETERS

GAS

ESOG furnished us with gas prices in effect at August 31, 1999 as shown
below.

DISTRICT $/MCF
-------- -----

Brenton..................................................... 2.619
Madison..................................................... 2.378
Weston...................................................... 2.780
Pikeville................................................... 2.703

OIL AND CONDENSATE

XB-7
189

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

APPALACHIAN NATURAL GAS TRUST

7,875,000 TRUST UNITS

---------------------

PROSPECTUS
, 1999

---------------------

LEHMAN BROTHERS

SALOMON SMITH BARNEY

PAINEWEBBER INCORPORATED

CIBC WORLD MARKETS

CREDIT SUISSE FIRST BOSTON

DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED

DONALDSON, LUFKIN & JENRETTE

A.G. EDWARDS & SONS, INC.

MCDONALD INVESTMENTS INC.

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
190

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

All capitalized terms used and not defined in Part II of this Registration
Statement shall have the meanings assigned to them in the Prospectus forming a
part of this Registration Statement.

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Except for the Registration Fee and the NASD Filing Fee, the following
itemized table sets forth estimates of those expenses payable by Eastern States
in connection with the offer and sale of the securities offered hereby:

Registration Fee............................................ $ 52,871
NASD Filing Fee............................................. 19,519
NYSE Listing Fee............................................ 103,850
Printing and Engraving Expenses............................. *
Legal Fees and Expenses..................................... *
Accountants' Fees and Expenses.............................. *
Trustee's Fees and Expenses................................. *
Blue Sky Fees............................................... *
Miscellaneous Fees and Expenses............................. *
--------
Total.............................................
========

- ---------------
* To be filed by amendment

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Section 7 of the Trust Agreement provides that the trustee will be
indemnified by Eastern States Oil & Gas, Inc., a Delaware corporation, against
any and all liability and expenses incurred by it individually or as trustee in
the administration of the trust and the trust estate, except for any liability
or expense resulting from willful misconduct, bad faith or gross negligence.

Subsection (a) of Section 145 of the General Corporation Law of the State
of Delaware ("DGCL") empowers a corporation to indemnify any person who was or
is a party or is threatened to be made a party to any threatened, pending or
completed action, suit or proceeding, whether civil, criminal, administrative or
investigative (other than an action by or in the right of the corporation) by
reason of the fact that he is or was a director, officer, employee or agent of
the corporation, or is or was serving at the request of the corporation as a
director, officer, employee or agent of another corporation, partnership, joint
venture, trust or other enterprise, against expenses (including attorneys'
fees), judgments, fines and amounts paid in settlement actually and reasonably
incurred by him in connection with such action, suit or proceeding if he acted
in good faith and in a manner he reasonably believed to be in or not opposed to
the best interests of the corporation, and, with respect to any criminal action
or proceeding, had no reasonable cause to believe his conduct was unlawful.

Subsection (b) of Section 145 empowers a corporation to indemnify any
person who was or is a party or is threatened to be made a party to any
threatened, pending or completed action or suit by or in the right of the
corporation to procure a judgment in its favor by reason of the fact that such
person acted in any of the capacities set forth above, against expenses
(including attorneys' fees) actually and reasonably incurred by him in
connection with the defense or settlement of such action or suit if he acted in
good faith and in a manner he reasonably believed to be in or not opposed to the
best interests of the corporation, except that no indemnification may be made in
respect of any claim, issue or matter as to which such person shall have been
adjudged to be liable to the corporation unless and only to the extent that the
Court of Chancery or the court in which such action or suit was brought shall
determine upon application that, despite the adjudication of liability but in
view of all the circumstances of the case, such person is fairly and reasonably
entitled to indemnity for such expenses which the Court of Chancery or such
other court shall deem proper.

II-1
191

Section 145 further provides that to the extent a director or officer of a
corporation has been successful on the merits or otherwise in the defense of any
action, suit or proceeding referred to in subsections (a) and (b) of Section 145
or in the defense of any claim, issue or matter therein, he shall be indemnified
against expenses (including attorneys' fees) actually and reasonably incurred by
him in connection therewith; that indemnification provided for by Section 145
shall not be deemed exclusive of any other rights to which the indemnified party
may be entitled; that indemnification provided by Section 145 shall, unless
otherwise provided when authorized or ratified, continue as to a person who has
ceased to be a director, officer, employee or agent and shall inure to the
benefit of such person's heirs, executors and administrators; and empowers the
corporation to purchase and maintain insurance on behalf of a director or
officer of the corporation against any liability asserted against him and
incurred by him in any such capacity, or arising out of his status as such,
whether or not the corporation would have the power to indemnify him against
such liabilities under Section 145.

Section 102(b)(7) of the DGCL provides that a certificate of incorporation
may contain a provision eliminating or limiting the personal liability of a
director to the corporation or its stockholders for monetary damages for breach
of fiduciary duty as a director, provided that such provisions may not eliminate
or limit the liability of a director (1) for any breach of the director's duty
of loyalty to the corporation or its stockholders, (2) for acts or omissions not
in good faith or which involve intentional misconduct or a knowing violation of
law, (3) under Section 174 (relating to liability for unauthorized acquisitions
or redemptions of, or dividends on, capital stock) of the DGCL or (4) for any
transaction from which the director derived an improper personal benefit.
Article VII of Eastern States' Amended and Restated Certificate of Incorporation
contains such a provision.

Section 8.07 of Eastern States' Amended and Restated Bylaws further
provides that:

"(a) The Corporation shall indemnify a director or officer of the
Corporation who is or was a party to any proceeding by reason of the fact
that he is or was such a director or officer or is or was serving at the
request of the Corporation as a director, officer, employee or agent of
another corporation, partnership, joint venture, trust, employee benefit
plan or other profit or non-profit enterprise against all liabilities and
expenses incurred in the proceeding to the maximum extent permissible under
applicable law.

(b) To the maximum extent permissible under applicable law, the
Corporation shall make advances and reimbursements for expenses incurred by
a director or officer in a proceeding upon receipt of an undertaking from
him to repay the same if it is ultimately determined that he is not
entitled to indemnification. Such undertaking shall be an unlimited,
unsecured general obligation of the director or officer and shall be
accepted without reference to his ability to make repayment. The Executive
Committee is hereby designated as an appropriate committee to authorize
such advances/reimbursements.

(c) The Board of Directors is hereby empowered, by majority vote of a
quorum of disinterested directors, to cause the Corporation to indemnify or
contract in advance to indemnify any other employee or agent of the
Corporation not specified in subsection (a) of this Section 8.07 who was or
is a party to any proceeding, by reason of the fact that he is or was an
employee or agent of the Corporation, or is or was serving at the request
of the Corporation as a director, officer, employee or agent of another
corporation, partnership, joint venture, trust, employee benefit plan or
other profit or non-profit enterprise, to the same extent as if such person
was specified as one to whom indemnification is granted in subsection (a).

(d) The Corporation may purchase and maintain insurance to indemnify
it against the whole or any portion of the liability assumed by it in
accordance with this Section 8.07 and may also procure insurance, in such
amounts as the Board of Directors may determine, on behalf of any person
who is or was a director, officer, employee or agent of another
corporation, partnership, joint venture, trust, employee benefit plan or
other enterprise, against any liability asserted against or incurred by
such person in any such capacity or arising from his status as such,
whether or not the Corporation would have power to indemnify him against
such liability under the provisions of this Section 8.07.
II-2
192

(e) In the event there has been a change in the composition of a
majority of the Board of Directors after the date of an alleged act or
omission with respect to which indemnification is claimed, any
determination as to indemnification and advancement of expenses with
respect to any claim for indemnification made pursuant to subsection (a) of
this Section 8.07 shall be made by special legal counsel agreed upon by the
Board of Directors and the proposed indemnitee. If the Board of Directors
and the proposed indemnitee are unable to agree upon such special legal
counsel, the Board of Directors and the proposed indemnitee each shall
select a nominee, and the nominees shall select such special legal counsel.

(f) The provisions of this Section 8.07 shall be applicable to all
actions, claims, suits or proceedings commenced after the adoption hereof,
whether arising from any action taken or failure to act before or after
such adoption. No amendment, modification or repeal of this Section 8.07
shall diminish the rights provided hereby or diminish the right to
indemnification with respect to any claim, issue or matter in any then
pending or subsequent proceeding that is based in any material respect on
any alleged action or failure to act prior to such amendment, modification
or repeal.

(g) Reference herein to directors, officers, employees or agents shall
include former directors, officers, employees and agents and their
respective heirs, executors and administrators.

(h) If any provision or provisions of this Section 8.07 shall be held
to be invalid, illegal or unenforceable for any reason whatsoever: (i) the
validity, legality and enforceability of the remaining provisions of this
Section 8.07 (including, without limitation, all portions of Section 8.07
containing any such provision held to be invalid, illegal or unenforceable,
that are not themselves invalid, illegal or unenforceable) shall not in any
way be affected or impaired thereby; and (ii) to the fullest extent
possible, the provisions of this Section 8.07 (including, without
limitation, all portions of Section 8.07 containing any such provision held
to be invalid, illegal or unenforceable, that are not themselves invalid,
illegal or unenforceable) shall be construed so as to give effect to the
intent manifested by the provision held invalid, illegal or unenforceable."

In addition, Eastern States and certain other persons may be entitled under
agreements entered into with agents or underwriters to indemnification by such
agents or underwriters against certain liabilities, including liabilities under
the Securities Act of 1933, or to contribution with respect to payments which
Eastern States or such persons may be required to make in respect thereof.

The above discussion of Eastern States' Amended and Restated Certificate of
Incorporation, Amended and Restated Bylaws and Sections 145 and 102(b)(7) of the
DGCL is not intended to be exhaustive and is qualified in its entirety by such
Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws
and statutes.

Additionally, Eastern States has acquired directors' and officers'
insurance in the amount of $10 million.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

None

ITEM 16. EXHIBITS.

EXHIBIT
NUMBER DESCRIPTION
------- -----------

II-3
193

EXHIBIT
NUMBER DESCRIPTION
------- -----------

** 4.3 -- Appalachian Natural Gas Trust -- Form of Amended and
Restated Trust Agreement.
** 5.1 -- Opinion of Richards, Layton & Fingers, P.A. as to the
legality of the securities offered hereby.
** 8.1 -- Form of Opinion of Andrews & Kurth L.L.P. regarding
federal income tax matters.
** 8.2 -- Form of Opinion of Goodwin & Goodwin regarding West
Virginia state tax matters.
** 8.3 -- Form of Opinion of Vorys, Sater, Seymour and Pease, LLP
regarding Kentucky state tax matters.
**10.1 -- Form of Net Overriding Royalty Conveyance.
*10.2 -- Amended and Restated Incentive Compensation Plan of
Statoil Energy, Inc.
*10.3.1 -- Employee Shareholders Agreement dated May 31, 1995 by and
among Statoil Energy, Inc. and the signatories thereto
who hold Statoil Energy, Inc. common stock and/or options
to purchase common stock.
*10.3.2 -- First Amendment to Employee Shareholders Agreement dated
June 6, 1997 by and among Statoil Energy and the
signatories thereto who hold Statoil Energy common stock
and/or options to purchase common stock.
*10.3.3 -- Second Amendment to Employee Shareholders Agreement dated
May 19, 1998 by and among Statoil Energy and the
signatories thereto who hold Statoil common stock and/or
options to purchase common stock.
*10.4 -- Promissory Note dated August 10, 1999 made by Eastern
States Oil & Gas, Inc. to Statoil Energy Holdings, Inc.
for the principal sum of $505,488,085.
*10.5.1 -- Employment Agreement between Clifton A. Brown and Statoil
Energy effective February 1, 1999.
*10.5.2 -- Employment Agreement between Stevens V. Gillespie and
Statoil Energy effective February 1, 1999.
**10.6 -- Gas Purchase Contract between Eastern States Oil & Gas,
Inc. and CNG Energy Services Corporation dated November
1, 1997.
**10.7 -- Gas Purchase Contract between Statoil Energy, Inc. and
CNG Producing Company dated August 1, 1998.
**10.8 -- Natural Gas Sales Agreement between Eastern Energy
Marketing, Inc. and Eastern States Oil & Gas, Inc. dated
October 23, 1996.
*21.1 -- Subsidiaries of Eastern States Oil & Gas, Inc.
**23.1 -- Consent of Ernst & Young LLP dated October 13, 1999.
**23.2 -- Consent of Richards, Layton & Fingers, P.A. (included in
the opinion filed as Exhibit 5.1).
**23.3 -- Form of Consent of Andrews & Kurth L.L.P. (included in
the opinion filed as Exhibit 8.1).
**23.4 -- Consent of Ryder Scott Company, L.P. Petroleum Engineers
dated October 13, 1999.
**23.5 -- Form of Consent of Goodwin & Goodwin (included in the
opinion filed as Exhibit 8.2).
**23.6 -- Form of Consent of Vorys, Sater, Seymour and Pease LLP
(included in the opinion filed as Exhibit 8.3).
*24.1 -- Power of attorney.
*27.1 -- Financial Data Schedule relating to Appalachian Natural
Gas Trust.
*27.2 -- Financial Data Schedule relating to Eastern States Oil &
Gas, Inc.

- ---------------

* Previously filed.

** Filed herewith.

II-4
194

ITEM 17. UNDERTAKINGS.

The registrants hereby undertake:

(a) To provide to the underwriters at the closing specified in the
underwriting agreement certificates in such denominations and registered in
such names as required by the underwriters to permit prompt delivery to
each purchaser.

(b) That, for purposes of determining any liability under the
Securities Act of 1933, the information omitted from the form of prospectus
filed as part of this Registration Statement in reliance upon Rule 430A and
contained in a form of prospectus filed by the registrants pursuant to Rule
424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed a part
of this Registration Statement as of the time it was declared effective.

(c) That, for the purpose of determining any liability under the
Securities Act of 1933, each post-effective amendment that contains a form
of prospectus shall be deemed to be a new registration statement relating
to the securities offered therein, and the offering of such securities at
that time shall be deemed to be the initial bona fide offering thereof.

Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of each
of the registrants pursuant to the provisions described in Item 14 above or
otherwise, each registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public policy
as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In
the event that claim for indemnification against such liabilities (other than
the payment by Eastern States of expenses incurred or paid by a director,
officer or controlling person of each of the registrants in the successful
defense of any action, suit or proceeding) is asserted by such director, officer
or controlling person in connection with the securities being registered, each
registrant will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of appropriate jurisdiction
the question whether such indemnification by it is against public policy as
expressed in the Securities Act of 1933 and will be governed by the final
adjudication of such issue.

II-5
195

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this Amendment No. 1 to the Registration Statement to be signed
on its behalf by the undersigned, thereunto duly authorized, in the City of
Alexandria, State of Virginia, on October 14, 1999.

EASTERN STATES OIL & GAS, INC.

By: /s/ CLIFTON A. BROWN
----------------------------------
Name: Clifton A. Brown
Title: President and Chief
Executive Officer

APPALACHIAN NATURAL GAS TRUST

By: EASTERN STATES OIL & GAS, INC.,
as sponsor

By: /s/ CLIFTON A. BROWN
----------------------------------
Name: Clifton A. Brown
Title: President and Chief
Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this Amendment
No. 1 to the Registration Statement has been signed by the following persons in
the capacities and on the dates indicated.

SIGNATURE TITLE DATE
--------- ----- ----

/s/ CLIFTON A. BROWN President and Chief Executive October 14, 1999
- ----------------------------------------------------- Officer (Principal Executive
Clifton A. Brown Officer)

/s/ STEVENS V. GILLESPIE Senior Vice President, Chief October 14, 1999
- ----------------------------------------------------- Financial Officer and
Stevens V. Gillespie Treasurer (Principal
Financial Officer and
Principal Accounting
Officer)

* Director October 14, 1999
- -----------------------------------------------------
David A. Dresner

* Director October 14, 1999
- -----------------------------------------------------
Kristian B. Hausken

II-6
196

SIGNATURE TITLE DATE
--------- ----- ----

* Director October 14, 1999
- -----------------------------------------------------
Jon A. Jacobsen

* Director October 14, 1999
- -----------------------------------------------------
Thor Otto Lohne

* Director October 14, 1999
- -----------------------------------------------------
Johan Nic Vold

*By /s/ CLIFTON A. BROWN
-------------------------------------------------
Clifton A. Brown
Attorney-in-Fact

II-7
197

EXHIBIT INDEX

ITEM 16. EXHIBITS.

EXHIBIT
NUMBER DESCRIPTION
------- -----------

** 1.1 -- Form of Underwriting Agreement.
* 3.1 -- Amended and Restated Certificate of Incorporation of
Eastern States Oil & Gas, Inc.
* 3.2 -- Amended and Restated Bylaws of Eastern States Oil & Gas,
Inc.
* 4.1.1 -- Certificate of Trust.
** 4.1.2 -- Certificate of Amendment to Certificate of Trust filed
October 8, 1999.
** 4.2 -- Appalachian Natural Gas Trust -- Restated Trust
Agreement, dated as of October 4, 1999.
** 4.3 -- Appalachian Natural Gas Trust -- Form of Amended and
Restated Trust Agreement.
** 5.1 -- Opinion of Richards, Layton & Fingers, P.A. as to the
legality of the securities offered hereby.
** 8.1 -- Form of Opinion of Andrews & Kurth L.L.P. regarding
federal income tax matters.
** 8.2 -- Form of Opinion of Goodwin & Goodwin regarding West
Virginia state tax matters.
** 8.3 -- Form of Opinion of Vorys, Sater, Seymour and Pease, LLP
regarding Kentucky state tax matters.
**10.1 -- Form of Net Overriding Royalty Conveyance.
*10.2 -- Amended and Restated Incentive Compensation Plan of
Statoil Energy, Inc.
*10.3.1 -- Employee Shareholders Agreement dated May 31, 1995 by and
among Statoil Energy, Inc. and the signatories thereto
who hold Statoil Energy, Inc. common stock and/or options
to purchase common stock.
*10.3.2 -- First Amendment to Employee Shareholders Agreement dated
June 6, 1997 by and among Statoil Energy and the
signatories thereto who hold Statoil Energy common stock
and/or options to purchase common stock.
*10.3.3 -- Second Amendment to Employee Shareholders Agreement dated
May 19, 1998 by and among Statoil Energy and the
signatories thereto who hold Statoil common stock and/or
options to purchase common stock.
*10.4 -- Promissory Note dated August 10, 1999 made by Eastern
States Oil & Gas, Inc. to Statoil Energy Holdings, Inc.
for the principal sum of $505,488,085.
*10.5.1 -- Employment Agreement between Clifton A. Brown and Statoil
Energy effective February 1, 1999.
*10.5.2 -- Employment Agreement between Stevens V. Gillespie and
Statoil Energy effective February 1, 1999.
**10.6 -- Gas Purchase Contract between Eastern States Oil & Gas,
Inc. and CNG Energy Services Corporation dated November
1, 1997.
**10.7 -- Gas Purchase Contract between Statoil Energy, Inc. and
CNG Producing Company dated August 1, 1998.
**10.8 -- Natural Gas Sales Agreement between Eastern Energy
Marketing, Inc. and Eastern States Oil & Gas, Inc. dated
October 23, 1996.
*21.1 -- Subsidiaries of Eastern States Oil & Gas, Inc.
**23.1 -- Consent of Ernst & Young LLP dated October 13, 1999.
**23.2 -- Consent of Richards, Layton & Fingers, P.A. (included in
the opinion filed as Exhibit 5.1).

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198

EXHIBIT
NUMBER DESCRIPTION
------- -----------

**23.3 -- Form of Consent of Andrews & Kurth L.L.P. (included in
the opinion filed as Exhibit 8.1).
**23.4 -- Consent of Ryder Scott Company, L.P. Petroleum Engineers
dated October 13, 1999.
**23.5 -- Form of Consent of Goodwin & Goodwin (included in the
opinion filed as Exhibit 8.2).
**23.6 -- Form of Consent of Vorys, Sater, Seymour and Pease LLP
(included in the opinion filed as Exhibit 8.3).
*24.1 -- Power of attorney.
*27.1 -- Financial Data Schedule relating to Appalachian Natural
Gas Trust.
*27.2 -- Financial Data Schedule relating to Eastern States Oil &
Gas, Inc.

- ---------------

* Previously filed.

** Filed herewith.

II-9