UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)

[ ]
    Registration statement pursuant to
    Section 12(b) or 12(g) of the Securities Exchange Act of 1934.or[X]
    Annual report pursuant to Section
    13 or 15(d) of the Securities Exchange Act of 1934.For the fiscal
    year ended December 31, 2003.Or[ ]
    Transition report pursuant to
    Section 13 or 15(d) of the Securities Exchange Act of 1934. For the transition period from
    ---------- to ---------- .Commission file number
    333-39826


ENTERRA ENERGY TRUST



Alberta, Canada

(Jurisdiction of Incorporation or Organization)

Suite 2600, 500  4th Avenue S.W.

Calgary, Alberta, Canada

T2P 2V6

(Address of Principal Executive Offices)

S

Title of Each Class
    Name of Each Exchange
    On Which RegisteredTrust Units
    Toronto Stock ExchangeNasdaq


Securities registered or to be registered pursuant to Section 12(g) of
the Act: None

Securities for which there is a reporting obligation pursuant to
Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the issuers
classes of capital or common stock as of the close of the period covered by the annual
report.

Trust Units, without par value at December 31, 2003: 18,955,960

Indicate by check mark whether the registrant: (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements for the past 90
days.  Yes [X] No [ ]

Indicate by check mark which financial statement item the registrant
has elected to follow.  Item 17 [ ] Item 18 [X]



ITEM 1. Identity of Directors, Senior Management and Advisors

Not applicable

ITEM 2. Offer Statistics and Expected Timetable

Not applicable

ITEM 3. Key Information

A. Selected Financial Data

SUMMARY CONSOLIDATED FINANCIAL DATA

The financial data set forth below as at December 31, 2003 and 2002 and
for each of the years in the three-year period ended December 31, 2003 have been derived
from our audited consolidated financial statements included in Item 18 of this Form 20-F.
Financial data at December 31, 2001, 2000 and 1999 and for each of the years in the
three-year period ended December 31, 2000 have been derived from our previously published
audited consolidated financial statements not included in this document.

The financial data as at December 31, 2003 and 2002 and for each of the
years in the three-year period ended December 31, 2003 should be read in conjunction with,
and are qualified in their entirety by reference to, our audited consolidated financial
statements.

The financial data is derived from our financial statements which have
been prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP),
the application of which, in the case of Enterra Energy Trust, conforms in all material
respects for the periods presented with US GAAP, except as disclosed in footnotes to the
financial statements.

The following table presents a summary of our consolidated statement of
operations derived from our financial statements for 2003, 2002, 2001, 2000 and 1999. The
monetary amounts in the table are based on Canadian generally accepted accounting
principles ("Canadian GAAP"). All data presented below should be read in
conjunction with the "Managements Discussion and Analysis of Financial
Condition and Results of Operations" and our financial statements and accompanying
notes included elsewhere in this Form 20-F.

Consolidated statements of operations data:

(In
    thousands, except per unit data)2003
    2002
    2001
    2000
    1999C$
    C$
    C$
    C$
    C$Amounts
    in accordance with Canadian GAAPRevenue
    $ 72,097
    $ 25,746
    $ 20,264
    $ 16,700
    $ 2,515Earnings
    (loss) from operations
    $ 12,835
    $ 2,909
    $ 3,228
    $ 4,175
    ($ 409)Net earnings
    (loss) for the year
    $ 5,004
    $ 4,977
    $ 1,617
    $ 2,453
    ($ 249)Basic
    earnings (loss) per unit/share
    $ 0.26
    $ 0.27
    $ 0.12
    $ 0.28
    ($0.05)Diluted
    earnings (loss) per unit/share
    $ 0.26
    $ 0.27
    $ 0.12
    $ 0.27
    ($0.05)Amounts
    in accordance with US GAAPRevenue
    $ 72,097
    $ 25,746
    $ 20,264
    $ 16,700
    $ 2,515Earnings
    (loss) from operations
    $ 18,016
    $ 5,969
    ($24,797)
    $ 4,175
    ($ 409)Net earnings
    (loss) for the year
    $ 6,510
    $ 6,748
    ($ 15,534)
    $ 2,628
    ($ 328Basic
    earnings (loss) per unit/share
    $ 0.34
    $ 0.37
    ($ 1.11)
    $ 0.27
    ($0.07)Diluted
    earnings (loss) per unit/share
    $ 0.34
    $ 0.36
    ($ 1.11)
    $ 0.26
    ($0.07)




The following table indicates a summary of our consolidated balance
sheets as of December 31, 2003, 2002, 2001, 2000 and 1999. The monetary amounts in the
table are based on Canadian GAAP.

Consolidated balance sheet data:

(In
    Thousands)
    As at December 312003
    2002
    2001
    2000
    1999C$
    C$
    C$
    C$
    C$Amounts
    in accordance with Canadian GAAPCash
    $ 66
    $ 108
    $ 43
    $ 1
    $ 42Accounts
    receivable and prepaids
    11,219
    7,971
    6,880
    2,505
    685Capital
    assets
    104,821
    94,354
    73,139
    18,335
    7,017Total assets
    116,230
    102,717
    80,063
    22,101
    7,744Total
    stockholders equity
    47,781
    38,663
    33,524
    7,371
    3,978Dividends
    paid on preferred shares
    $33
    $23
    -
    -
    -Dividends
    paid on common shares
    -
    -
    -
    -
    -Amounts
    in accordance with US GAAPCash
    $ 66
    $ 108
    $ 43
    $ 1
    $ 42Accounts
    receivable and prepaids
    11,219
    7,971
    6,880
    2,505
    685Capital
    assets
    84,288
    68,308
    43,693
    18,085
    6,835Total assets
    95,696
    76,670
    50,616
    22,076
    7,562Total
    unitholders equity
    33,997
    23,373
    16,373
    7,545
    3,978Dividends
    paid on preferred shares
    $33
    $23
    -
    -
    -Dividends
    paid on common shares
    -
    -
    -
    -
    -




We publish our consolidated financial statements in Canadian dollars.
In this prospectus, except where otherwise indicated, all dollar amounts are stated in
Canadian dollars. References to "$" or "Cdn.$" are to Canadian dollars
and references to "US$" are to U.S. dollars. The following table sets forth for
each period indicated the period end exchange rates for conversion of U.S. dollars to
Canadian dollars, the average exchange rates on the last day of each month during such
period and the high and low exchange rates during such period. These rates are based on
the noon buying rate in New York City, expressed in U.S. dollars, for cable transfers in
Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New
York. The exchange rates are presented as Canadian dollars per $1.00. On March 31, 2004,
the noon buying rate was US$1.00 equals Cdn.$ 1.3081and the inverse noon buying rate was
Cdn.$1.00 equals US$0.7648.

U.S. Dollar/Canadian Dollar Exchange Rates for Five Most Recent
Financial Years

**Year Ended December 31,**
    **2003**
    **2002**
    **2001**
    **2000**
    **1999**End of period
    0.7738
    0.6344
    0.6285
    0.6669
    0.6918Average for the period
    0.7139
    0.6372
    0.6456
    0.6732
    0.6691High during the period
    0.7738
    0.6656
    0.6714
    0.6969
    0.6935Low during
    the period
    0.6349
    0.6175
    0.6227
    0.6410
    0.6464


U.S. Dollar/Canadian Exchange
Rates for Previous Six Months

**October   2003**
    **November 2003**
    **December 2003**
    **January   2004**
    **February 2004**
    **March     
    2004**High
    0.7680
    0.7731
    0.7747
    0.7883
    0.7650
    0.7659Low
    0.7371
    0.7440
    0.7447
    0.7481
    0.7398
    0.7357


-3-



Not Applicable

C. Reasons for the Offer and Use of Proceeds

Not Applicable

D. Risk Factors





Oil and natural gas prices have fluctuated widely during recent years
and are subject to fluctuations in response to relatively minor changes in supply, demand,
market uncertainty and other factors that are beyond our control. These factors include,
but are not limited to, worldwide political instability, foreign supply of oil and natural
gas, the level of consumer product demand, government regulations and taxes, the price and
availability of alternative fuels and the overall economic environment. Any decline in
crude oil or natural gas prices may have a material adverse effect on our operations,
financial condition, borrowing ability, reserves and the level of expenditures for the
development of oil and natural gas reserves. Any resulting decline in our cash flow could
reduce distributions.

We use financial derivative instruments and other hedging mechanisms to
try to limit a portion of the adverse effects resulting from changes in natural gas and
oil commodity prices. To the extent we hedge our commodity price exposure, we forego the
benefits we would otherwise experience if commodity prices were to increase. In addition,
our commodity hedging activities could expose us to losses. Such losses could occur under
various circumstances, including where the other party to a hedge does not perform its
obligations under the hedge agreement, the hedge is imperfect or our hedging policies and
procedures are not followed. Furthermore, we cannot guarantee that such hedging
transactions will fully offset the risks of changes in commodities prices.

In addition, we regularly assess the carrying value of our assets in
accordance with Canadian generally accepted accounting principles under the full cost
method. If oil and natural gas prices become depressed or decline, the carrying value of
our assets could be subject to downward revision.

An increase in operating costs or a decline in our production level
could have a material adverse effect on our results of operations and financial condition
and, therefore, could reduce distributions to unitholders as well as affect the market
price of the trust units.

Higher operating costs for our underlying properties will directly
decrease the amount of cash flow received by the Trust and, therefore, may reduce
distributions to our unitholders. Electricity, chemicals, supplies, reclamation and
abandonment and labour costs are a few of the operating costs that are susceptible to
material fluctuation.

The level of production from our existing properties may decline at
rates greater than anticipated due to unforeseen circumstances, many of which are beyond
our control. A significant decline in our production could result in materially lower
revenues and cash flow and, therefore, could reduce the amount available for distributions
to unitholders.

Distributions may be reduced during periods in which we make capital
expenditures or debt repayments using cash flow, which could also affect the market price
of our trust units.

To the extent that we use cash flow to finance acquisitions,
development costs and other significant expenditures, the net cash flow that the Trust
receives that is available for distribution to unitholders will be reduced. Hence, the
timing and amount of capital expenditures may affect the amount of net cash flow received
by the Trust and, as a consequence, the amount of cash available to distribute to
unitholders. Therefore, distributions may be reduced, or even eliminated, at times when
significant capital or other expenditures are made.

-4-

The board of directors of Enterra has the discretion to determine the
extent to which cash flow from Enterra will be allocated to the payment of debt service
charges as well as the repayment of outstanding debt, including under the credit facility.
Funds used for such purposes will not be payable to the Trust. As a consequence, the
amount of funds retained by Enterra to pay debt service charges or reduce debt will reduce
the amount of cash available for distribution to unitholders during those periods in which
funds are so retained.

A decline in our ability to market our oil and natural gas production
could have a material adverse effect on production levels or on the price that we received
for our production which, in turn, could reduce distributions to unitholders as well as
affect the market price of our trust units.

Our business depends in part upon the availability, proximity and
capacity of gas gathering systems, pipelines and processing facilities. Canadian federal
and provincial, as well as United States federal and state, regulation of oil and gas
production, processing and transportation, tax and energy policies, general economic
conditions, and changes in supply and demand could adversely affect our ability to produce
and market oil and natural gas. If market factors change and inhibit the marketing of our
production, overall production or realized prices may decline, which could reduce
distributions to our unitholders.

Fluctuations in foreign currency exchange rates could adversely affect
our business, and could affect the market price of our trust units as well as
distributions to unitholders.

The price that we receive for a majority of our oil and natural gas is
based on United States dollar denominated benchmarks, and therefore the price that we
receive in Canadian dollars is affected by the exchange rate between the two currencies. A
material increase in the value of the Canadian dollar relative to the United States dollar
may negatively impact net production revenue by decreasing the Canadian dollars received
for a given United States dollar price. We could be subject to unfavourable price changes
to the extent that we have engaged, or in the future engage, in risk management activities
related to foreign exchange rates, through entry into forward foreign exchange contracts
or otherwise.

If we are unable to acquire additional reserves, the value of our trust
units and distributions to unitholders may decline.

We do not actively explore for oil and natural gas reserves. Instead,
we add to our oil and natural gas reserves primarily through development, exploitation and
acquisitions. As a result, future oil and natural gas reserves are highly dependent on our
success in exploiting existing properties and acquiring additional reserves. We also
distribute the majority of our net cash flow to unitholders rather than reinvesting it in
reserve additions. Accordingly, if external sources of capital, including the issuance of
additional trust units, become limited or unavailable on commercially reasonable terms,
our ability to make the necessary capital investments to maintain or expand our oil and
natural gas reserves will be impaired. To the extent that we are required to use cash flow
to finance capital expenditures or property acquisitions, the level of cash flow available
for distribution to unitholders will be reduced. Additionally, we cannot guarantee that we
will be successful in developing additional reserves or acquiring additional reserves on
terms that meet our investment objectives. Without these reserve additions, our reserves
will deplete and as a consequence, either production from, or the average reserve life of,
our properties will decline. Either decline may result in a reduction in the value of our
trust units and in a reduction in cash available for distributions to unitholders.

Actual reserves will vary from reserve estimates, and those variations
could be material, and affect the market price of our trust units and distributions to
unitholders.

The reserve and recovery information contained in the independent
engineering report prepared by McDaniel & Associates Consultants Ltd.
("McDaniel") relating to Enterra's 2003 reserves is only an estimate and the
actual production and ultimate reserves from our properties may be greater or less than
the estimates prepared by McDaniel.

The value of our trust units depends upon, among other things, the
reserves attributable to our properties. Estimating reserves is inherently uncertain.
Ultimately, actual reserves attributable to our properties will vary from estimates, and
those variations may be material. The reserve figures contained herein are only estimates.
A number of factors are considered and a number of assumptions are made when estimating
reserves. These factors and assumptions include, among others:

-5-

- historical production in the area compared with production rates from
    similar producing areas;
- future commodity prices, production and development costs, royalties
    and capital expenditures;
- initial production rates;
- production decline rates;
- ultimate recovery of reserves;
- success of future development activities;
- marketability of production;
- effects of government regulation; and
- other government levies that may be imposed over the producing life
    of reserves.

Reserve estimates are based on the relevant factors, assumptions and
prices on the date the relevant evaluations were prepared. Many of these factors are
subject to change and are beyond our control. If these factors, assumptions and prices
prove to be inaccurate, actual results may vary materially from reserve estimates.

If we expand our operations beyond oil and natural gas production in
western Canada, we may face new challenges and risks.

If we were unsuccessful in managing these challenges and risks, our
results of operations and financial condition could be adversely affected, which could
affect the market price of our trust units and distributions to unitholders.

Our operations and expertise are currently focused on conventional oil
and gas production and development in the Western Canadian Sedimentary Basin. In the
future, we may acquire oil and gas properties outside this geographic area. In addition,
the Trust Indenture does not limit the activities to oil and gas production and
development, and we could acquire other energy related assets, such as oil and natural gas
processing plants or pipelines. Expansion of our activities into new areas may present
challenges and risks that we have not faced in the past. If we do not manage these
challenges and risks successfully, our results of operations and financial condition could
be adversely affected.

In determining the purchase price of acquisitions, we rely on both
internal and external assessments relating to estimates of reserves that may prove to be
materially inaccurate. Such reliance could adversely affect the market price of our trust
units and distributions to unitholders.

The price we are willing to pay for reserve acquisitions is based
largely on estimates of the reserves to be acquired. Actual reserves could vary materially
from these estimates. Consequently, the reserves we acquire may be less than expected,
which could adversely impact cash flows and distributions to unitholders. An initial
assessment of an acquisition may be based on a report by engineers or firms of engineers
that have different evaluation methods and approaches than those of our engineers, and
these initial assessments may differ significantly from our subsequent assessments.

Some of our properties are not operated by us and, therefore, results
of operations may be adversely affected by the failure of third-party operators, which
could affect the market price of our trust units and distributions to unitholders.

The continuing production from a property, and to some extent the
marketing of that production, is dependent upon the ability of the operators of those
properties. At December 31, 2003, approximately % of our daily production was from
properties operated by third parties. To the extent a third-party operator fails to
perform its functions efficiently or becomes insolvent, our revenue may be reduced. Third
party operators also make estimates of future capital expenditures more difficult.

Further, the operating agreements which govern the properties not
operated by us typically require the operator to conduct operations in a good and
"workmanlike" manner. These operating agreements generally provide, however,
that the operator has no liability to the other non-operating working interest owners,
such as unitholders, for losses sustained or liabilities incurred, except for liabilities
that may result from gross negligence or wilful misconduct.

-6-

Delays in business operations could adversely affect distributions to
unitholders and the market price of our trust units.

In addition to the usual delays in payment by purchasers of oil and
natural gas to the operators of our properties, and the delays of those operators in
remitting payment to us, payments between any of these parties may also be delayed by:

- restrictions imposed by lenders;
- accounting delays;
- delays in the sale or delivery of products;
- delays in the connection of wells to a gathering system;
- blowouts or other accidents;
- adjustments for prior periods;
- recovery by the operator of expenses incurred in the operation of the
    properties; or
- the establishment by the operator of reserves for these expenses.

Any of these delays could reduce the amount of cash available for
distribution to unitholders in a given period and expose us to additional third party
credit risks.

We may, from time to time, finance a significant portion of our
operations through debt. Our indebtedness may limit the timing or amount of the
distributions that are paid to unitholders, and could affect the market price of our trust
units.

The payments of interest and principal, and other costs, expenses and
disbursements to our lenders reduces amounts available for distribution to unitholders.
Variations in interest rates and scheduled principal repayments could result in
significant changes to the amount of the cash flow required to be applied to the debt
before payment of any amounts to the unitholders. The agreements governing our credit
facility provide that if we are in default under the credit facility, exceed certain
borrowing thresholds or fail to comply with certain covenants, we must repay the
indebtedness at an accelerated rate, and the ability to make distributions to unitholders
may be restricted.

Our lenders have been provided with a security interest in
substantially all of our assets. If we are unable to pay the debt service charges or
otherwise commit an event of default, such as bankruptcy, our lenders may foreclose on and
sell the properties. The proceeds of any sale would be applied to satisfy amounts owed to
the creditors. Only after the proceeds of that sale were applied towards the debt would
the remainder, if any, be available for distribution to unitholders.

Our current credit facility and any replacement credit facility may not
provide sufficient liquidity.

The amounts available under our existing credit facility may not be
sufficient for future operations, or we may not be able to obtain additional financing on
economic terms attractive to us, if at all. Our current credit facility consists of a
revolving operating demand loan. Repayment of all outstanding amounts may be demanded at
any time. If this occurs, we may need to obtain alternate financing. Any failure to obtain
suitable replacement financing may have a material adverse effect on our business, and
distributions to unitholders may be materially reduced.

We have a working capital deficiency at December 31, 2003; our credit
facilities can be called at any time. Any material change in our liquidity could impair
our ability to pay dividends and could adversely affect the value of your investment.

Our credit facilities are classified as a short-term liability on our
balance sheet as they are on a demand basis and may be called at any time. Accordingly, at
December 31, 2003, we had a working capital deficiency of $ 38.2 million, which means our
current liabilities exceeded our current assets by that amount. Although we are not
subject to and do not expect to make principal repayments under our current banking
arrangement, they could be called for repayment at any time. Other than in the event of a
default or a breach of covenants, we do not expect to make any principal payments in 2004.

Our assets are highly leveraged. Any material change in our liquidity
could impair our ability to pay dividends and could adversely affect the value of your
investment.

We carry a high amount of debt relative to our assets. A decrease in
the amount of our production or the price we receive for it could make it difficult for us
to service our debt or may cause the bank that issued our loan to determine that our
assets are insufficient security for our bank debt.

-7-

The oil and natural gas industry is highly competitive.

We compete for capital, acquisitions of reserves, undeveloped lands,
skilled personnel, access to drilling rigs, service rigs and other equipment, access to
processing facilities, pipeline and refining capacity and in many other respects with a
substantial number of other organizations, many of which may have greater technical and
financial resources than we do. Some of these organizations not only explore for, develop
and produce oil and natural gas but also carry on refining operations and market oil and
other products on a worldwide basis. As a result of these complementary activities, some
of our competitors may have greater and more diverse competitive resources to draw on than
we do. Given the highly competitive nature of the oil and natural gas industry, this could
adversely affect the market price of our trust units and distributions to unitholders.

The industry in which we operate exposes us to potential liabilities
that may not be covered by insurance.

Our operations are subject to all of the risks associated with the
operation and development of oil and natural gas properties, including the drilling of oil
and natural gas wells, and the production and transportation of oil and natural gas. These
risks include encountering unexpected formations or pressures, premature declines of
reservoirs, blow-outs, equipment failures and other accidents, cratering, sour gas
releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather
conditions, pollution, other environmental risks, fires and spills. A number of these
risks could result in personal injury, loss of life, or environmental and other damage to
our property or the property of others. We cannot fully protect against all of these
risks, nor are all of these risks insurable. We may become liable for damages arising from
these events against which we cannot insure or against which we may elect not to insure
because of high premium costs or other reasons. Any costs incurred to repair these damages
or pay these liabilities would reduce funds available for distribution to unitholders.

The operation of oil and natural gas wells could subject us to
environmental claims and liability.

The oil and natural gas industry is subject to extensive environmental
regulation pursuant to local, provincial and federal legislation. A breach of that
legislation may result in the imposition of fines or the issuance of "clean up"
orders. Legislation regulating the oil and natural gas industry may be changed to impose
higher standards and potentially more costly obligations. For example, the 1997 Kyoto
Protocol to the United Nation's Framework Convention on Climate Change, known as the Kyoto
Protocol, was ratified by the Canadian government in December, 2002 and will require,
among other things, significant reductions in greenhouse gases. The impact of the Kyoto
Protocol on us is uncertain and may result in significant additional costs (future) for
our operations. Although we record a provision in our financial statements relating to our
estimated future environmental and reclamation obligations, we cannot guarantee that we
will be able to satisfy our actual future environmental and reclamation obligations.

We are not fully insured against certain environmental risks, either
because such insurance is not available or because of high premium costs. In particular,
insurance against risks from environmental pollution occurring over time (as opposed to
sudden and catastrophic damages) is not available on economically reasonable terms.

Accordingly, our properties may be subject to liability due to hazards
that cannot be insured against, or that have not been insured against due to prohibitive
premium costs or for other reasons. Any site reclamation or abandonment costs actually
incurred in the ordinary course of business in a specific period will be funded out of
cash flow and, therefore, will reduce the amounts available for distribution to
unitholders. Should we be unable to fully fund the cost of remedying an environmental
problem, we might be required to suspend operations or enter into interim compliance
measures pending completion of the required remedy.

Lower crude oil and natural gas prices increase the risk of ceiling
limitation write-downs. Any write-downs could materially affect the value of your
investment.

We changed our method of accounting for petroleum and natural gas
properties from the "successful efforts" method to the "full cost"
method in 2001. All costs related to the exploration for and the development of oil and
gas reserves are capitalized into a single cost centre representing Enterras
activity which is undertaken exclusively in Canada. Costs capitalized include land
acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped
properties and costs of drilling productive and non-productive wells. Proceeds from the
disposal of properties are applied as a reduction of cost without recognition of a gain or
loss except where such disposals would result in a major change in the depletion rate.

-8-



We perform a cost recovery ceiling test which limits net capitalized
costs to the undiscounted estimated future net revenue from proven oil and gas reserves
plus the cost of unproven properties less impairment, using year-end prices or average
prices in that year, if appropriate. In addition, the value is further limited by
including financing costs, administration expenses, future abandonment and site
restoration costs and income taxes. Under U.S. GAAP, companies using the "full
cost" method of accounting for oil and gas producing activities perform a ceiling
test using discounted estimated future net revenue from proven oil and gas reserves using
a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for this
reconciliation were those in effect at the applicable year-end. Financing and
administration costs are excluded from the calculation under U.S. GAAP. At December 31,
2001 Enterra realized a U.S. GAAP ceiling test write-down of Cdn.$17,500,000, after tax.
There were no such write-down required at December 31, 2002 or 2003.

The risk that we will be required to write down the carrying value of
crude oil and natural gas properties increases when crude oil and natural gas prices are
low or volatile. We may experience additional ceiling test write-downs in the future.

Unforeseen title defects may result in a loss of entitlement to
production and reserves.

Although we conduct title reviews in accordance with industry practice
prior to any purchase of resource assets, such reviews do not guarantee that an unforeseen
defect in the chain of title will not arise and defeat our title to the purchased assets.
If such a defect were to occur, our entitlement to the production from such purchased
assets could be jeopardized and, as a result, distributions to unitholders may be reduced.

Aboriginal Land Claims

The economic impact on us of claims of aboriginal title is unknown.
Aboriginal people have claimed aboriginal title and rights to a substantial portion of
western Canada. We are unable to assess the effect, if any, that any such claim would have
on our business and operations.

Changes in tax and other laws may adversely affect unitholders.

Income tax laws, other laws or government incentive programs relating
to the oil and gas industry, such as the treatment of mutual fund trusts and resource
allowance, may in the future be changed or interpreted in a manner that adversely affects
the Trust and unitholders. Tax authorities having jurisdiction over the Trust or the
unitholders may disagree with the manner in which we calculate our income for tax purposes
or could change their administrative practices to our detriment or the detriment of
unitholders. The Department of Finance (Canada) has indicated that it will continue to
evaluate the development of the income trust market as part of its ongoing monitoring and
assessment of Canadian financial markets and the Canadian tax system. Accordingly, changes
in this area are possible.

Income Tax Matters

On October 31, 2003, the Department of Finance (Canada) released, for
public comment, proposed amendments to the Tax Act that relate to the deductibility of
interest and other expenses for income tax purposes for taxation years commencing after
2004. In general, the proposed amendments may deny the realization of losses in respect of
a business if there is no reasonable expectation that the business will produce a
cumulative profit over the period that the business can reasonably be expected to be
carried on. If such proposed amendments were enacted and successfully invoked by the CCRA
against the Trust or a subsidiary entity, it could materially adversely affect the amount
of distributable cash available. However, Enterra believes that it is reasonable to expect
the Trust and each subsidiary entity to produce a cumulative profit over the expected
period that the business will be carried on.

-9-

Expenses incurred by Enterra are only deductible to the extent they are
reasonable. Although the Trust is of the view that all expenses to be claimed by the Trust
and its subsidiary entities should be reasonable and deductible, there can be no assurance
that CCRA will agree. If CCRA were to successfully challenge the deductibility of such
expenses, the return to unitholders may be adversely affected.

The Trust Indenture provides that an amount equal to the taxable income
of the Trust will be payable each year to unitholders in order to reduce the Trusts
taxable income to zero. Where in a particular year, the Trust does not have sufficient
available cash to distribute such an amount to unitholders, the Trust Indenture provides
that additional trust units must be distributed to unitholders in lieu of cash payments.
unitholders will generally be required to include an amount equal to the fair market value
of those trust units in their taxable income, notwithstanding that they do not directly
receive a cash payment.

As noted above, the Department of Finance (Canada) has indicated that
it will continue to evaluate the development of the income trust market as part of its
ongoing monitoring and assessment of Canadian financial markets and the Canadian tax
system. Accordingly, changes in this area are possible. Such changes could result in the
income tax considerations described under the heading "Canadian Federal Income Tax
Considerations" being materially different in certain respects.

There would be material adverse tax consequences if the Trust lost its
status as a mutual fund trust under Canadian tax laws.

It is intended that the Trust continue to qualify as a mutual fund
trust for purposes of the Tax Act. The Trust may not, however, always be able to satisfy
any future requirements for the maintenance of mutual fund trust status. Should the status
of the Trust as a mutual fund trust be lost or successfully challenged by a relevant tax
authority, certain adverse consequences may arise for the Trust and unitholders. Some of
the significant consequences of losing mutual fund trust status are as follows:

> The Trust would be taxed on certain types of income distributed to
>       unitholders, including income generated by the royalties held by the Trust. Payment of
>       this tax may have adverse consequences for some unitholders, particularly unitholders that
>       are not residents of Canada and residents of Canada that are otherwise exempt from
>       Canadian income tax.
>     The Trust would cease to be eligible for the capital gains refund
>       mechanism available under Canadian tax laws if it ceased to be a mutual fund trust.
>     Trust units held by unitholders that are not residents of Canada
>       would become taxable Canadian property. These non-resident holders would be subject to
>       Canadian income tax on any gains realized on a disposition of trust units held by them.
>     The trust units would not constitute qualified investments for
>       Registered Retirement Savings Plans, or "RRSPs", Registered Retirement Income
>       Funds, or "RRIFs", Registered Education Savings Plans, or "RESPs", or
>       Deferred Profit Sharing Plans, or "DPSPs". If, at the end of any month, one of
>       these exempt plans holds trust units that are not qualified investments, the plan must pay
>       a tax equal to 1% of the fair market value of the trust units at the time the trust units
>       were acquired by the exempt plan. An RRSP or RRIF holding non-qualified trust units would
>       be subject to taxation on income attributable to the trust units. If an RESP holds
>       non-qualified trust units, it may have its registration revoked by the Canada Customs and
>       Revenue Agency.

In addition, we may take certain measures in the future to the extent
we believe them necessary to ensure that the Trust maintains its status as a mutual fund
trust. These measures could be adverse to certain holders of trust units.

Rights as a unitholder differ from those associated with other types of
investments.

The trust units do not represent a traditional investment in the oil
and natural gas sector and should not be viewed by investors as shares in the Trust or
Enterra. The trust units represent an equal fractional beneficial interest in the Trust
and, as such, the ownership of the trust units does not provide unitholders with the
statutory rights normally associated with ownership of shares of a corporation, including,
for example, the right to bring "oppression" or "derivative" actions.
The unavailability of these statutory rights may also reduce the ability of unitholders to
seek legal remedies against other parties on our behalf.

The trust units are also unlike conventional debt instruments in that
there is no principal amount owing to unitholders. The trust units will have minimal value
when reserves from our properties can no longer be economically produced or marketed.
unitholders will only be able to obtain a return of the capital they invested during the
period when reserves may be economically recovered and sold. Accordingly, cash
distributions do not represent a "yield" in the traditional sense as they
represent both return of capital and return on investment and the distributions received
over the life of the investment may not meet or exceed the initial capital investment.

-10-

Changes in market-based factors may adversely affect the trading price
of our trust units.

The market price of our trust units is primarily a function of
anticipated distributions to unitholders and the value of our properties. The market price
of our trust units is therefore sensitive to a variety of market based factors, including,
but not limited to, interest rates and the comparability of our trust units to other yield
oriented securities. Any changes in these market-based factors may adversely affect the
trading price of the trust units.

Our operations are entirely independent from the unitholders and loss
of key management and other personnel could impact our business.

Unitholders are entirely dependent on the management of Enterra with
respect to the acquisition of oil and gas properties and assets, the development and
acquisition of additional reserves, the management and administration of all matters
relating to our oil and natural gas properties and the administration of the Trust. The
loss of the services of key individuals who currently comprise the management team could
have a detrimental effect on the Trust. Investors should carefully consider whether they
are willing to rely on the existing management before investing in the trust units.

There may be future dilution.

One of our objectives is to continually add to our reserves through
acquisitions and through development. Since we do not reinvest a material portion of our
cash flow, our success is, in part, dependent on our ability to raise capital from time to
time by selling additional trust units. unitholders will suffer dilution as a result of
these offerings if, for example, the cash flow, production or reserves from the acquired
assets do not reflect the additional number of trust units issued to acquire those assets.
unitholders may also suffer dilution in connection with future issuances of trust units to
effect acquisitions.

There may not always be an active trading market for the trust units.

While there is currently an active trading market for our trust units
in the United States and Canada, we cannot guarantee that an active trading market will be
sustained.

The limited liability of unitholders is uncertain.

Due to uncertainties in the law relating to investment trusts, there is
a risk that a unitholder could be held personally liable for obligations of the Trust in
respect of contracts or undertakings which the Trust enters into and for certain
liabilities arising otherwise than out of contracts including claims in tort, claims for
taxes and possibly certain other statutory liabilities. Although every written contract or
commitment of the Trust must contain an express disavowal of liability of the unitholders
and a limitation of liability to Trust property, such protective provisions may not
operate to avoid unitholder liability. Notwithstanding attempts to limit unitholder
liability, unitholders may not be protected from liabilities of the Trust to the same
extent that a shareholder is protected from the liabilities of a corporation. Further,
although the Trust has agreed to indemnify and hold harmless each unitholder from any
costs, damages, liabilities, expenses, charges and losses suffered by the unitholder
resulting from or arising out of that unitholder not having limited liability, the Trust
cannot guarantee that any assets would be available in these circumstances to reimburse
unitholders for any such liability.

The redemption rights of unitholders is limited.

Unitholders have a limited right to require the Trust to repurchase
their trust units, which is referred to as a redemption right. It is anticipated that the
redemption right will not be the primary mechanism for unitholders to liquidate their
investment. The Trust's ability to pay cash in connection with a redemption is subject to
limitations. Any securities which may be distributed in specie to unitholders in
connection with a redemption may not be listed on any stock exchange and a market may not
develop for such securities. In addition, there may be resale restrictions imposed by law
upon the recipients of the securities pursuant to the redemption right.

-11-

Taxation of Enterra

Enterra is subject to taxation in each taxation year on its income for
the year, after deducting interest paid to the Trust on the Note and after deducting
payments, if any, made to the Trust with respect to the Royalty Agreement. During the
period that Exchangeable Shares issued by Enterra are outstanding, a portion of the cash
flow from operations will be subject to tax to the extent that there are not sufficient
resource pool deductions, capital cost allowance or utilization of prior years non-capital
losses to reduce taxable income to zero. Enterra intends to deduct, in computing its
income for tax purposes, the full amount available for deduction in each year associated
with its income tax resource pools, undepreciated capital cost ("UCC") and
non-capital losses, if any. If there are not sufficient resource pools, UCC and
non-capital losses carried forward to shelter the income of Enterra, then cash taxes would
be payable by Enterra. In addition, there can be no assurance that taxation authorities
will not seek to challenge the amount of interest expense relating to the Note. If such a
challenge were to succeed against Enterra, it could materially adversely affect the amount
of cash flow available for distribution to unitholders.

Further, interest on the Note accrues at the Trust level for income tax
purposes whether or not actually paid. The Trust Indenture provides that an amount equal
to the taxable income of the Trust will be distributed each year to unitholders in order
to reduce the Trust's taxable income to zero. Where interest payments on the Notes are due
but not paid in whole or in part, the Trust Indenture provides that any additional amount
necessary to be distributed to unitholders may be distributed in the form of Units rather
than in cash. unitholders will be required to include such additional amount in income
even though they do not receive a cash distribution.

We may undertake acquisitions that could limit our ability to manage
and maintain our business, result in adverse accounting treatment and are difficult to
integrate into our business. Any of these events could result in a material change in our
liquidity, impair our ability to pay dividends and could adversely affect the value of
your investment.

A component of future growth will depend on the ability to identify,
negotiate, and acquire additional companies and assets that complement or expand existing
operations. However we may be unable to complete any acquisitions, or any acquisitions we
may complete may not enhance our business. Any acquisitions could subject us to a number
of risks, including:

> diversion of management's attention;
>     inability to retain the management, key personnel and other employees
>       of the acquired business;
>     inability to establish uniform standards, controls, procedures and
>       policies;
>     inability to retain the acquired company's customers;
>     exposure to legal claims for activities of the acquired business
>       prior to acquisition; and inability to integrate the acquired company and its employees
>       into our organization effectively.

Since we are a Canadian company and most of our assets and key
personnel are located in Canada, you may not be able to enforce a U.S. judgment for claims
you may bring against us, our assets, our key personnel or many of the experts named in
this prospectus. This may prevent you from receiving compensation to which you would
otherwise be entitled.

We have been organized under the laws of Alberta, Canada and all of our
assets are located outside the U.S. In addition, a majority of the members of our Board of
Directors and our officers and many of the experts named in this prospectus are residents
of countries other than the U.S. As a result, it may be impossible for you to effect
service of process upon us or these individuals within the U.S. or to enforce any
judgments in civil and commercial matters, including judgments under U.S. federal
securities laws. In addition, a Canadian court may not permit you to bring an original
action in Canada or to enforce in Canada a judgment of a U.S. court based upon civil
liability provisions of the U.S. federal securities laws.

-12-

ITEM 4. Information on the Trust

BUSINESS



Enterra Energy Trust (the "Trust", "Enterra" and,
together with its direct and indirect subsidiaries and partnerships, "we",
"our" or "us") is an open ended unincorporated investment trust
governed by the laws of the Province of Alberta and created pursuant to a trust indenture
dated as of October 24, 2003, between Enterra Energy Corp. and Olympia Trust Company (the
"Trust Indenture"). Our head and principal office is located at 2600, 500 
4th Avenue S.W., Calgary, Alberta, T2P 2V6.

As a result of the completion of a plan of arrangement involving the
Trust, Enterra Energy Corp. ("Old Enterra"), Enterra Acquisition Corp. and
Enterra Energy Commercial Trust ("EEC Trust") (the "Arrangement") on
November 25, 2003, former holders of common shares of Enterra Corp. received two trust
units or two Exchangeable Shares of Enterra Acquisition Corp., in accordance with the
elections made by such holders, and Old Enterra becoming a subsidiary of the Trust. Old
Enterra was subsequently amalgamated with Enterra Acquisition Corp. to form Enterra Energy
Corp. ("New Enterra")

The principal undertaking of the Trust is to issue trust units and to
acquire and hold debt instruments, royalties and other interests. The direct and indirect
wholly owned subsidiaries of the Trust carry on the business of acquiring and holding
interests in petroleum and natural gas properties and assets related thereto.

We make monthly cash distributions to unitholders from our net cash
flow. Our primary sources of cash flow are interest payments from New Enterra and EEC
Trust on the principal amounts of the Note and the CT Note, respectively.

Olympia Trust Company has been appointed as trustee under the Trust
Indenture. The beneficiaries of the Trust are holders of the outstanding trust units. The
principal and head office of Olympia Trust Company is located at 2300, 125  9th
Avenue S.E., Calgary, Alberta T2G 0P6.

New Enterra

New Enterra is the principal operating subsidiary of the Trust. New
Enterra was formed on the amalgamation of Enterra Acquisition Corp., Big Horn Resources
Ltd., Enterra Sask. Ltd. and Enterra Energy Corp. on November 25, 2003 pursuant to the
Arrangement and is governed by the laws of the Province of Alberta. EEC Trust is the sole
holder of voting shares of New Enterra. All of the crude oil and natural gas properties
and related assets in which the Trust has an interest are held, directly or indirectly,
through New Enterra.

The Partnership

Enterra Production Partnership (the "Partnership") was formed
as a general partnership under the laws of the Province of Alberta on August 16, 2001. The
Partnership currently holds all of our producing crude oil and natural gas properties from
which we ultimately derive our cash flow. The partners of the Partnership are New Enterra
and Enterra Energy Partner Corp.



Enterra Energy Commercial Trust is a commercial trust governed by the
laws of the Province of Alberta. The Trust holds 100% of the issued and outstanding trust
units of EEC Trust. EEC Trust 100% of the issued and outstanding common shares of New
Enterra.

History

Old Enterra (formerly Westlinks Resources Ltd.) was organized on June
30, 1998 by the statutory amalgamation of Temba Resources Ltd. and PTR Resources Ltd.
pursuant to the provisions of the Business Corporations Act (Alberta). Temba
Resources Ltd. was incorporated in Alberta on July 31, 1996. Immediately prior to the
amalgamation which created Old Enterra, Temba Resources Ltd. amalgamated with its wholly
owned subsidiary, Rainee Resources Ltd. PTR Resources Ltd. was incorporated in Alberta on
September 18, 1992 as 542275 Alberta Ltd., changed its name to Ablevest Holdings Ltd. on
June 14, 1993, and to PTR Resources Ltd. on December 1, 1997.

I



-13-

In September 1999, Old Enterra acquired a 94% working interest in four
producing oil wells and a saltwater disposal well in the Sylvan Lake area of Alberta.

In May 2000, Old Enterra acquired, effective January 1, 2000, further
working interests in the Sounding Lake area of Alberta, consisting of a further 36%
working interest in the Dina sand pool as well as working interests averaging
approximately 91% in 21 producing oil wells. The purchase price for such interests was
$11,900,000.

On November 15, 2000, Old Enterra sold, effective October 1, 2000, all
of its interests in the Bigoray area of Alberta for cash consideration of $4,494,500.
Proceeds from the sale were used to reduce Old Enterra's bank debt and to fund its 2001
acquisition program.

On December 6, 2000, Old Enterra acquired a 25% working interest in a
producing gas well in the Altares area of northeast British Columbia for cash
consideration of $1,000,000.

On January 17, 2001, Old Enterra completed a secondary public offering
in the United States of 1,000,000 units, each unit consisting of one common share and one
share purchase warrant, for U.S. $4.55 per unit. The share purchase warrants were
exercisable for six months at U.S. $4.50 per share. Net proceeds from the offering were
used for Old Enterra's 2001 acquisition and drilling program.

On February 28, 2001, Old Enterra entered into a farm-out and option
agreement whereby it was granted to ability to earn an interest in over 12,000 acres of
land in the Altares region of northeast British Columbia. Under the terms of the farm-out
and option agreement, Old Enterra was obligated to drill a minimum of two wells and had an
option to drill up to four more wells to earn an interest in all of the lands.

On March 27, 2001, Old Enterra acquired an average 67% working interest
in 8,705 gross acres of land and 34 producing oil wells in the Grand Forks area of
southern Alberta for cash consideration of $5,500,000. The effective date of the
acquisition was January 1, 2001.

On April 23, 2001, Old Enterra entered into the EuroGas Agreement. On
June 5, 2001, Old Enterra completed the acquisition of an aggregate of 8,275,500 Big Horn
shares from EuroGas.

On June 12, 2001, Old Enterra entered into an agreement with a private
company to acquire certain oil and gas assets in the Superb area of Saskatchewan. The
purchase price fort the assets was $2,800,000, which amount was satisfied by the payment
of $1,500,000 in cash and through the issuance of Common Shares. Through this acquisition,
Old Enterra acquired a 91% working interest in four existing Waseca heavy oil wells with a
combined production rate of approximately 180 Bbls/d.



Effective December 10, 2001, Westlinks Resources Ltd. (i.e., Old
Enterra) changed its name to Enterra Energy Corp.

On March 26, 2002, Old Enterra redeemed 6,123,870 of its Series I
Preferred Shares for $2,300,000, resulting in a gain of $2,905,290.

On April 12, 2002, Old Enterra was granted a 30-day extension for the
1,000,000 share purchase warrants which were exercisable until April 17, 2002. The expiry
date was extended to May 17, 2002. The warrants expired on May 17, 2002 without being
exercised.

On October 8, 2002, Old Enterra raised $5 million for a sale-leaseback
arrangement on some of its production equipment.



-14-

On October 8, 2002, Old Enterra purchased 3,300 acres of land in one of
its core areas for $2.5 million.

Old Enterra received $18.3 million in 2003 as proceeds on the sale of miscellaneous
non-core properties. These proceeds were applied to reduce bank debt and improve working
capital.

On June 20, 2003, Old Enterras common shares commenced trading on
the Toronto Stock exchange under the symbol "ENT". They were previously trading
on the TSX Venture Exchange.

On August 5, 2003 Old Enterra announced its intention to reorganize
itself into an oil and gas income trust.

On September 30, 2003, Old Enterra redeemed all 611,803 outstanding
Series I Preferred Shares for $520,032.

On October 27, 2003 The American Stock Exchange began trading in
options in Old Enterra under the symbol "EMU".

Old Enterras plan of arrangement in respect of the
reorganization of Old Enterra into Enterra Energy Trust received overwhelming approval at
the special shareholder meeting held on November 24, 2003. Shareholders voted 99.37% in
favor of the arrangement resolution. The transaction also received the approval of the
Court of Queens Bench of Alberta on November 24, 2003. The transaction became
effective on November 25, 2003. The trust units of Enterra Energy Trust commenced trading
on the Nasdaq under "EENC" and the Toronto Stock Exchange under
"ENT.un" on Friday November 28, 2003. After the transaction, the Trust had a
total of 18,951,556 trust units issued and outstanding. In addition, New Enterra had a
total of 2,000,000 exchangeable shares issued and outstanding.

The registered office of the Corporation is located at Suite 3300, 421
 7th Avenue S.W., Calgary, Alberta, T2P 4K9 and its head office is
located at Suite 2600, 500-4th Avenue S.W., Calgary, Alberta T2P 2V6.

Our business



Business Strategy

Enterras business strategy is to grow its reserves and
distributions by acquiring properties which provide additional production and potential
for development upside. Enterra is focused on per unit growth. We will finance
acquisitions with both debt and equity, the optimal mix being one which minimizes
unitholders dilution while maintaining a strong balance sheet. Enterras
ability to replace and grow its reserves over time is the key success factor in our
business strategy.

Properties

Enterra's core areas included the Peace River Arch area of Alberta,
Central Alberta and East Central Alberta. Enterra also has a large inventory of prospects,
the development of which could significantly increase the size of Enterras existing
production and reserve base.

Peace River Arch of Alberta

Clair

The Clair property is located 13 km north of the city of Grande
Prairie, Alberta. Enterras assets include a 100% working interest in 3,840 acres of
land, 20 producing oil wells and an oil treating facility. Gas is conserved and processed
at the Encana Sexsmith gas plant.

Production is primarily from the Doe Creek (Dunvegan) formation with a
small amount of gas production from the Charlie Lake and Halfway. Production is light, 44
degree API gravity crude and solution gas is produced from the Doe Creek oil pool. At
December 31, 2003 there were 20 oil wells producing a combined 2,175 bbl/d of oil and 2.1
mmcf/d of solution gas. One dually completed Charlie Lake and Halfway gas well also
produces combined daily gas of 400 mcf/d. Enterra has a 100% working interest in this
well. To date, Enterra has drilled or recompleted 29 wells for oil and seven wells for
water injection. There are no further drilling plans for the pool. Enterra has received
waterflood approval in June 2003 (with two recent amendment approvals) and is in the final
stages of achieving 100% voidage replacement pending minor waterflood modifications. Nine
wells shut-in in 2003 due to excessive gas production will be reactivated once pressure
support from the waterflood is received at the wells.



-15-

Total proved reserves assigned to the Doe Creek A
(Dunvegan) pool are 1,997 mbbl of oil, 1,236 mmcf of gas and 38 mbbl of natural gas
liquids. Total proved and probable reserves assigned to the Doe Creek A
(Dunvegan) pool are 2,998 mbbl of oil, 1,633 mmcf of gas and 51 mbbl of natural gas
liquids. The probable reserves category contains the incremental reserves and net present
value of the waterflood. McDaniel and Associates have stated that the additional reserves
associated with the waterflood would be moved into the proven category in a staged
approach. Critical stages include the achievement of 100% voidage replacement and
continued performance. Total proved reserves assigned to the 13-07-073-5W6 Charlie Lake /
Halfway gas well are 256 mmcf of gas and 8 mbbl of natural gas liquids. Total proved and
probable reserves assigned to the Charlie Lake / Halfway gas well are 368 mmcf of gas and
11 mbbl of natural gas liquids.

Enterra also owns and operates a central oil treating facility at Clair
which was connected into the Pembina Peace Pipeline system in September 2003.

Gordondale

The Gordondale property is located 75 km northwest of the city of
Grande Prairie, Alberta. Enterras assets included an average working interest of 79%
in 6,240 gross acres of land as well as two flowing gas wells, one gas well awaiting tie
in and one oil well. Production is currently from the Upper Kiskatinaw and Halfway zones.
Enterras share of production for the property was 300 mcf/d of gas, 8 bbl/d of oil
and 4 bbl/d of natural gas liquids. The property was sold in December 2003.

McDaniel and Associates had assigned Companys share of total
proved reserves to Gordondale of 164 mmcf of gas, 2 mbbl of oil, and 2 mbbl of natural
liquids. Total proved and probable reserves were 217 mmcf of gas, 3 mbbl of oil, and 3
mbbl of natural gas liquids.

Rolla

The Rolla property is located 70 km north of the city of Grande
Prairie, Alberta. Enterras assets include a 50% working interest in 1,920 acres of
land, 3 operated producing gas wells and a 12.5% working interest in two field
compressors. Enterras share of current gas production is approximately 800 mcf/d
from three 50% working interest Dunvegan gas wells. This gas is processed at the Duke
Midstream, Gordondale East gas plant.

Total proved reserves assigned to the Dunvegan are 512 mmcf of gas, and
total proved and probable reserves assigned to the Dunvegan are 725 mmcf of gas. All of
the proved reserves are in the proved producing category. The Dunvegan sand development in
the Rolla area is part of a large Delta complex from the northwest.

Hines Creek

The Hines Creek property is located 150 km north of the city of Grande
Prairie, Alberta. Enterras assets include a 50% working interest in 5,760 acres of
land, one producing gas well and one shut-in gas well currently awaiting a fracture
stimulation. Enterras share of current gas production is approximately 850 mcf/d
from the 50% working interest well, and expects Enterras share of production from
the 50% working interest shut-in well to be in excess of 200 mcf/d.

Total proved reserves assigned to the Hines Creek property are 728 mmcf
of gas, and total proved and probable reserves are 882 mmcf of gas. All of the proved
reserves are in the proved producing category.

East Central Alberta

Sounding Lake

The Sounding Lake package is located 10 km southwest of the town of
Provost, Alberta. Enterras assets include an average working interest of 58.7% in
5,496 gross acres of land as well as 56 producing oil wells and 2 producing gas wells.
Production is obtained primarily from the Dina, Cummings and Belly River formations. The
three main oil pools are Sounding Lake West, Sounding Lake East, and Sounding Lake North.
Enterras share of current production for the entire area is 520 bbl/d of oil and
1,700 mcf/d of gas. Enterra has and continues to upgrade pump sizes to maximize oil
production and upgrade oil batteries to handle higher volumes of total fluid and injection
water. Enterra has also tied-in the flared solution gas from two of its key facilities in
the area.

Enterra was assigned proved reserves at Sounding Lake of 741 mbbl of
oil and 1,451 mmcf of natural gas. Total proved and probable reserves are 926 mbbl oil and
1,870 mmcf natural gas based on improved performance from the existing wells.

-16-

Central Alberta

Sylvan Lake

The Sylvan Lake property is located 40 km west of the town of Red Deer,
Alberta. Enterras assets include an average working interest of 74.8% in 4,320 gross
acres of land as well as 24 producing oil wells and 1 producing gas well. Enterra
completed the development of 40-acre spacing wells in the Pekisko G pool, increasing the
number of producing wells from five to 24 wells. The property currently produces 1,225
bbl/d (gross), 1,100 bbl/day (net) of 14 degree API oil from 24 wells with 850 mcf/d (net)
of associated gas plus an additional 30 mcf/d (net) of non-associated gas. Production is
flowlined into a central treating facility constructed in September 2003 which is owned
and operated by Enterra Energy. Non-associated gas is conserved and flowlined to the Husky
Sylvan Lake gas plant. Clean oil is trucked from the facility to sales.

McDaniel and Associates has assigned total proved  reserves of
1,814 mbbl of oil, 1,014 mmcf of solution gas, and 32 mmcf of non-associated gas to this
property. Total proved and probable reserves are 2,404 mbbl of oil, 1,344 mmcf of solution
gas, and 40 mmcf of non-associated gas. Probable reserves were assigned based on an
assumption that the wells will achieve a slightly higher oil recovery than estimated.
Based on the success of the 2003 drilling program, Enterra plans to drill seven wells with
further downspacing in the centre of the pool as well as initiate a waterflood feasibility
study for the pool. The reservoir has net pays up to 40 m (130 ft). Enterra owns a 3-D
seismic program that covers the Sylvan Lake Pekisko G pool.

Kaybob

This property is located 50 kilometers north of Edson, Alberta and is
pipeline connected to a major gas and oil processing facility in the area. There is one
well with a working interest of 100% on production in this property. With the construction
of a pipeline tie-in in September 2003 and the addition of a gas-lift system in November
2003, the well was returned to production. The well is producing 130 bbl/d light crude oil
with 110 mcf/d of associated gas.

McDaniel and Associates have assigned total proved reserves of 391 mbbl
of oil, 230 mmcf of gas, and 8 mbbl of natural gas liquids to this property. Total proved
and probable reserves are 548 mbbl of oil, 323 mmcf of gas, and 11 mbbl of natural gas
liquids. Enterra acquired its interest in the Kaybob South Nisku C Pool in the year 2000.
Enterra owns a 90% working interest in 320 acres of land, subject to a 7.5% NCORR on 100%
of production. Enterra has a licensed copy of a 7 square mile 3-D program over the well
and adjacent lands.

Reserves and Present Value Summary

Enterra is  required to comply with the National Instrument 51-101, issued by the
Canadian Securities Administrators, in all its reserves related disclosures. NI 51-101
came into effect on September 30, 2003 and is applicable for financial years ended on or
after December 31, 2003. NI 51-101 brought about significant changes in which reporting
issuers manage and publicly disclose information relating to their oil and gas reserves,
mandates annual disclosure requirements and prescribes new reserve definitions as follows:Proved reserves (P90) - this is a conservative estimate of remaining reserves. For
reported reserves this means there must be at least a 90 percent probability that the
quantities actually recovered will equal or exceed the estimated proved reserves.Proved plus Probable (P50) - this is a reasonable estimate of remaining reserves.
For reported reserves there must be at least a 50 percent probability that the quantities
actually recovered will equal or exceed the sum of the proved plus probable reserves. The
probable reserves will no longer be risked by 50 percent as they are implicitly risked due
to the nature of the new definition of reserves.

The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and
comparability of oil and gas activities by reporting issuers and elevate reserves
reporting to a higher level of accountability.

In the United States, registrants [other than foreign private issuers] are
required to disclose reserves using the standards contained in U.S. Regulation S-X, and
the standardized measure of discounted future net cash flows relating to proved oil and
gas reserves determined in accordance with United States Statement of Financial Accounting
Standards No.69 "Disclosures About Oil and Gas Producing Activities''("FAS
69'').  As a foreign private issuer, Enterra is permitted to comply with the
disclosure requirements contained in NI 51-101 for the purposes of its U.S. regulatory
filings.  Unless otherwise indicated, all of the reserves and production information
disclosure in this Form 20-F is in compliance with NI 51-101.

-17-

The primary differences between the U.S. requirements and the NI 51-101 requirements are
that (i)the U.S. standards require disclosure only of proved reserves, whereas NI 51-101
requires disclosure of proved and probable reserves, and (ii)the U.S. standards require
that the reserves and related future net revenue be estimated under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is made, whereas
NI 51-101 requires disclosure of proved reserves and the related future net revenue
estimated using constant prices and costs as at the last day of the financial year, and of
proved and probable reserves and related future net revenue using forecast prices and
costs.  The definitions of proved reserves also differ, but according to the Canadian
Oil and Gas Evaluation Handbook (the reference source for the definition of proved
reserves under NI 51-101), differences in the estimated proved reserve quantities based on
constant prices should not be material.  Enterra concurs with this assessment.
In this Form 20-F, certain natural gas volumes have been converted to barrels of oil
equivalent (""BOEs'')on the basis of six thousand cubic feet
(""Mcf'')to one barrel (""bbl'').  BOEs may be misleading,
particularly if used in isolation.  A BOE conversion ratio of six Mcf to one bbl is
based on an energy equivalency conversion method primarily applicable at the burner tip
and does not represent equivalency at the well head.

Reserve volumes and values at December 31, 2003 are based
on Enterra's interest in its total proved and probable reserves prior to royalties as
defined in NI 51-101. Reserve volumes and values for previous years are based on
"established" (proved plus 50% probable) reserves prior to deduction of
royalties. Under those definitions, probable reserves were discounted by an arbitrary risk
factor of 50% in reporting established reserves. Under NI 51-101 reserves definitions,
estimates are prepared such that the full proved and probable reserves are estimated to be
recoverable (proved plus probable reserves are effectively a "most likely
case"). As such, the probable reserves now reported are already "risked".
Overall there were no material revisions to Enterra's reserve volumes in transitioning to
NI 51-101.

Enterra had its reserves evaluated by independent engineers every year.
Enterra's 2003 reserves were independently evaluated as at December 31, 2003 by McDaniel
and Associates Consultants Ltd. ("McDaniel") for all its properties, excluding
the properties acquired in East Central Alberta. This acquisition was completed on January
30, 2004 and was evaluated by Gilbert Lausten Jung Associates Ltd. ("GLJ").

Reserve ContinuityOil and Gas (mboe)Proved
    Probable
    TotalDecember 31, 2000
    2,261.4
    643.5
    2,904.9Discoveries and extensions
    1,224.8
    615.2
    1,840.0Purchases
    3,277.1
    981.7
    4,258.8Dispositions
    (113.1)
    (30.0)
    (143.1)Production
    (695.5)
    -
    (695.5)Revision of prior estimates
    (67.7)
    56.1
    (11.6)December 31, 2001
    5,887.0
    2,236.7
    8,153.5Discoveries and extensions
    3,502.9
    2,292.8
    5,795.7Dispositions
    (931.9)
    (441.1)
    (1,373.0)Production
    (846.7)
    -
    (846.7)Revision of prior estimates
    (235.0)
    (423.6)
    (658.6)December 31, 2002
    7,376.3
    3,694.6
    11,070.9Discoveries and extensions
    2,800.6
    860.1
    3,660.7Purchases
    139.5
    32.4
    171.9Dispositions
    (1,707.2)
    (929.6)
    (2,636.8)Production
    (1,833.2)
    -
    (1,833.2)Revision of prior estimates
    (633.1)
    (1,365.6)
    (1,998.7)December 31, 2003
    6,142.9
    2,291.9
    8,434.8Acquisition East Central Alberta
    properties
    2,377.2
    1,051.0
    3,428.2Total
    8,520.1
    3,342.9
    11,863.0






-18-

Enterras finding costs over the last 3 years are highlighted below, along with
the recycle ratios for each year. The recycle ratio is a critical measure of any success
in the oil and gas industry. It compares the netbacks with the finding costs. Basically, a
recycle ratio of 1 is a "break even point", indicating that the enterprise earns
the same amount when selling its production as it pays when finding new production.



Finding
    costs and recycle ratio(in
    $/boe, except for capital expenditures which are in thousands)3-year
    average
    2003
    2002
    2001Capital expenditures (including
    East Central acquisition)
    
    $71,424
    $35,881
    $49,309ReservesProved reserves added in the year
    (in mboe)
    13,322.0
    5,317.4
    3,502.8
    4,501.8Probable reserves added in the
    year (in mboe)
    5,800.6
    1,911.1
    2,292.6
    1,596.9Established
    reserves added in the year (in mboe) (1)
    17,177.8
    7,228.5
    4,649.1
    5,300.2Finding costsProved reserves ($/boe)
    $11.76
    $13.43
    $10.24
    $10.95Established reserves ($/boe)
    $9.12
    $9.88
    $7.72
    $9.30Recycle ratio (netbacks divided
    by finding costs)Corporate netbacks ($/boe) (2)
    $17.63
    $20.08
    $14.89
    $14.52Corporate recycle ratio (based on
    established finding costs)
    1.93
    2.03
    1.93
    1.56Operating netbacks ($/boe) (3)
    $20.28
    $22.72
    $18.34
    $16.18Operating
    recycle ratio (based on established reserves)
    2.22
    2.30
    2.38
    1.74(1) Established
    reserves were proved plus 1/2 probable reserves in 2001 and 2002, and proved plus probable
    reserves in 2003(2) Corporate
    netbacks are production revenue less royalties, operating costs, G&A and interest
    expense(3)
    Operating netbacks are production revenue less royalties and operating costs






The following table is based on the McDaniel and GLJ reports that show
the estimated share of the remaining oil, natural gas and natural gas liquids attributable
to Enterra and the estimated present value of estimated future net cash flows for these
reserves, using escalating prices and costs. All estimates of present value of future net
cash flows are stated after provision for capital expenditures required to generate such
revenues but prior to provision for indirect costs such as general and administrative
overhead, income taxes or interest expense. It should not be assumed that the estimated
present values of future net cash flows are representative of the fair market value of the
reserves. These recovery and reserve estimates of Enterras interests in the
described properties are estimates only; the actual reserves in the properties in which we
have an interest may be more or less than those calculated. Assumptions and qualifications
relating to costs, prices and other matters are summarized in the notes to the following
table. The extent and character of the material information supplied by Enterra including,
but not limited to, ownership, well data, production, price, revenues, operating costs and
contracts were relied upon by McDaniel and GLJ in preparing the report. In the absence of
such information, McDaniel and GLJ relied upon their opinion of reasonable practice in the
industry. The McDaniel and GLG reports may be examined at the office of Enterra located at
Suite 2600, 500- 4th Avenue S.W., Calgary, Alberta during normal business
hours. All monetary amounts are expressed in Canadian dollars.

-19-

Estimated Petroleum and Natural Gas Reserves and Net Present Value

December 31, 2003

Light/
    Medium
    Oil
    (mbbl)
    Heavy
    Oil
    (mbbl)
    Natural
    Gas
    (mmcf)
    NGLs
    (mmbl)
    Total
    (mboe)
    NPV0%
    10%
    15%McDaniel reportProved Producing
    2,563.7
    1,814.4
    5,330.1
    45.3
    5,311.8
    $78,467
    $67,943
    $63,458Proved Non-Producing
    679.8
    0.0
    774.0
    22.2
    831.0
    $18,315
    $15,277
    $14,188Total Proved
    3,243.5
    1,814.4
    6,104.1
    67.5
    6,142.8
    $96,782
    $83,220
    $77,646Total Probable
    1,359.0
    589.7
    1,926.7
    22.2
    2,292.0
    $41,065
    $28,661
    $24,664Total Proved and Probable
    4,602.5
    2,404.1
    8,030.8
    89.7
    8,434.8
    $137,847
    $111,881
    $102.310GLJ reportProved Producing
    1,390.9
    349.9
    1243.7
    25.1
    1,973.2
    $15,354
    $12,159
    $11,122Proved Non-Producing
    114.2
    223.2
    378.2
    3.5
    404.0
    $2,827
    $1,611
    $1,301Total Proved
    1,505.1
    573.1
    1,621.9
    28.6
    2,377.2
    $18,181
    $13,770
    $12,423Total Probable
    393.5
    407.0
    1,347.3
    25.9
    1,051.0
    $6,843
    $4,262
    $3,534Total Proved and Probable
    1,898.6
    980.1
    2,969.2
    54.5
    3,428.2
    $25,024
    $18,032
    $15,957Combined reportsProved Producing
    3,954.6
    2,164.3
    6,573.8
    70.4
    7,285.0
    $93,821
    $80,102
    $74,580Proved Non-Producing
    794.0
    223.2
    1,152.2
    25.7
    1,235.0
    $21,142
    $16,888
    $15,489Total Proved
    4,748.6
    2,387.5
    7,726.0
    96.1
    8,520.0
    $114,963
    $96,990
    $90.069Total Probable
    1,752.5
    996.7
    3,274.0
    48.1
    3,343.0
    $47,908
    $32,923
    $28,198Total Proved
    and Probable
    6,501.1
    3,384.2
    11,000.0
    144.2
    11,863.0
    $162,871
    $129,913
    $118,267


Historical Reserves

The following table sets out Enterras proved oil and gas reserves
at December 31, 2003, 2002 and 2001 respectively. The monetary amounts are expressed in
Canadian dollars.

As at December 312003 (1)
    2002
    2001Proved Producing Reserves:Oil and NGLs (mbbls)
    4,447
    4,443
    3,431Gas (mmcf)
    5,334
    10,930
    7,684Proved Reserves:Oil and NGLs (mbbls)
    5,149
    5,803
    4,133Gas (mmcf)
    6,108
    13,287
    10,707(1)
    including East Central Alberta acquisition






At December 31 Enterra had the following land holdings

2003
    2002
    2001Developed acres (net)
    13,394
    28,355
    22,646Undeveloped acres (net)
    42,686
    51,581
    58,590Total acres (net)
    56,080
    79,936
    81,236


-20-

Production

The following table summarizes Enterras working interest
production during the periods indicated:

Years ended December 31,2003
    2002
    2001
    2000
    1999
    1998
    1997Oil and NGLs (MBbls)
    1,409
    533
    582
    410
    93
    86
    79Gas (MMcf)
    2,545
    1,882
    680
    63
    61
    220
    58Total (MBOE)
    1,834
    847
    695
    421
    100
    108
    85Average
    Production in BOED
    5,024
    2,320
    1,906
    1,150
    274
    296
    233


D

"BOEPD" means barrels of oil equivalent produced per
day.

"MBOE" means thousands of barrels of oil equivalent,
meaning one barrel of oil or one barrel of natural gas liquids or ten mcf of natural gas.

"MBbls" means thousands of barrels, with respect to
production of crude oil or natural gas liquids.

"MMcf" means millions of cubic feet, with respect to
production of natural gas.

"NGLs" means natural gas liquids, being those
hydrocarbon components recovered from raw natural gas as liquids by processing through
extraction plants or recovered from field separators, scrubbers or other gathering
facilities. These liquids include the hydrocarbon components ethane, propane, butanes and
pentanes plus, or a combination thereof.



Drilling

Enterras drilling history is as follows (there were no wells
drilled in 1997 and 1999):

2003
    2002
    2001
    2000
    1998Wells
    drilled
    Gross (Net)
    Gross (Net)
    Gross (Net)
    Gross (Net)
    Gross (Net)Oil
    31 (31.0)
    25 (23.7)
    9 (4.97)
    9 (8.26)
    0 (0.00)Natural Gas
    3 (1.1)
    37 (34.0)
    8 (3.78)
    2 (1.27)
    0 (0.00)Injection and water disposal
    6 (6.0)Abandoned
    7 (6.4)
    0 (00.0)
    3 (1.84)
    2 (1.14)
    1 (0.13)Total
    47 (44.5)
    62 (57.7)
    20 (10.59)
    13 (10.67)
    1 (0.13)


_

Notes:

> (1) "Gross" wells means the number of whole wells.
>   (2) "Net" wells means Enterras working interest in the
>   gross wells.

Capital Expenditures

The following table summarizes the capital expenditures made by Enterra
during the periods indicated, expressed in Canadian dollars:

(In Thousands)
    Years ended December 31,2003
    2002
    2001
    2000
    1999
    1998
    1997Property acquisitions (net of disposals)
    ($9,724)
    $ 383
    $52,374
    $ 8,220
    $ 1,879
    $ 244
    $ 500Drilling (exploration and development)
    28,390
    21,090
    5,821
    6,922
    341
    27
    50Facilities
    14,368
    9,347
    1,412
    56
    728
    4
    0Miscellaneous
    286
    235
    1,011
    156
    24
    2
    34Total
    $ 33,320
    $ 30,289
    $68,618
    $ 15,354
    $2,972
    $ 277
    $ 584






Oil and Gas Wells

The following table summarizes Enterras interest in producing and
non-producing oil and gas wells as at December 31, 2003:

Property
    
    Producing
    Oil Wells
    Gross
    Producing
    Oil Wells
    Net
    Producing
    Gas Wells
    Gross
    Producing
    Gas Wells
    NetKaybob
    
    1
    0.9Highvale
    
    
    
    2
    0.75Leduc
    
    1
    0.39Garden Plains
    
    
    
    1
    0.62Gilby
    
    
    
    1
    0.39Leedale
    
    
    
    1
    0.02Lubicon
    
    1
    0.23Willesden Green
    
    101
    5.98
    1
    0.43Timber Draw
    
    1
    0.15Sounding Lake East
    
    17
    16.50Sounding Lake West
    
    55
    27.50Sounding Lake North
    
    22
    6.92Sylvan Lake
    
    24
    22.75
    1
    0.32Clair
    
    28
    28.00
    5
    5.00Gordondale
    
    1
    0.50
    2
    1.00Rolla
    
    
    
    2
    1.00Swan Hills
    
    1
    0.50Campbell
    
    1
    0.12Total Wells
    
    254
    110.44
    16
    9.53


Employees

At December 31, 2003 we had approximately 30 employees and consultants
working both in the Calgary head office and in field operations.

Office Facilities

Enterra currently leases 10,450 square feet of office space at Suite 2600, 500 - 4th
Avenue S.W. in Calgary, Alberta in a lease that commenced November 1, 2001. The lease has
a three-year term (expiring on November 30, 2004) and the annual rental is currently
C$28.64 per square foot (including operating costs and property taxes).

Competition

The petroleum industry is highly competitive. Enterra competes with
numerous other participants in the acquisition of oil and gas leases and properties, and
the recruitment of employees. Any company can make acquisitions and bid on provincial
leases in Alberta. Competitors include oil companies and other income trusts, many of whom
have greater financial resources, staff and facilities than those of Enterra.  Our
ability to increase reserves in the future will depend not only on our ability to develop
existing properties, but also on our ability to select and acquire suitable additional
producing properties or prospects for drilling. We also compete with numerous other
companies in the marketing of oil. Competitive factors in the distribution and marketing
of oil include price and methods and reliability of delivery.

Government Regulation in Canada

The oil and natural gas industry is subject to extensive controls and
regulations governing its operations, including land tenure, exploration, development,
production, refining, transportation and marketing, imposed by legislation enacted by
various levels of government and with respect to pricing and taxation of oil and natural
gas by agreements among the governments of Canada, Alberta and British Columbia, all of
which should be carefully considered by investors in the Canadian oil and gas industry. It
is not expected that any of these controls or regulations will affect the operations of
Enterra in a manner materially different from how they would affect other oil and gas
companies of similar size operating in Western Canada. All current legislation is a matter
of public record and Enterra is unable to predict what additional legislation or
amendments may be enacted. Outlined below are some of the principal aspects of
legislation, regulations and agreements governing the oil and gas industry.



-22-

Pricing and Marketing  Oil and Natural Gas

The producers of oil are entitled to negotiate sales contracts directly
with oil purchasers, with the result that the market determines the price of oil. Such
price depends in part on oil quality, prices of competing oils, distance to market, the
value of refined products and the supply/demand balance. Oil exporters are also entitled
to enter into export contracts with terms not exceeding one year in the case of light
crude oil and two years in the case of heavy crude oil, provided that an order approving
such export has been obtained from the National Energy Board of Canada, or NEB. Any oil
export to be made pursuant to a contract of longer duration, to a maximum of 25 years,
requires an exporter to obtain an export licence from the NEB and the issuance of such
licence requires the approval of the Governor in Council. In addition, the prorationing of
capacity on the interprovincial pipeline systems continues to limit oil exports.

The price of natural gas is determined by negotiation between buyers
and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the
Government of Canada. Exporters are free to negotiate prices with purchasers, provided
that the export contracts meet certain other criteria prescribed by the NEB and the
Government of Canada. Natural gas exports for a term of less than two years or for a term
of two to twenty years, in quantities of not more than 30,000 m3/day, must be
made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of
longer duration, up to a maximum of 25 years, or a larger quantity, requires an exporter
to obtain an export licence from the NEB and the issuance of such licence requires the
approval of the Governor in Council.

The governments of British Columbia and Alberta also regulate the
volume of natural gas which may be removed from those provinces for consumption elsewhere
based on such factors as reserve ability, transportation arrangements and market
considerations.

Provincial Royalties and Incentives

In addition to federal regulation, each province has legislation and
regulations which govern land tenure, royalties, production rates, environmental
protection and other matters. The royalty regime is a significant factor in the
profitability of crude oil, natural gas liquids, sulphur and natural gas production.
Royalties payable on production from lands other than Crown lands are determined by
negotiations between the mineral owner and the lessee, although production from such lands
is subject to certain provincial taxes and royalties. Crown royalties are determined by
governmental regulation and are generally calculated as a percentage of the value of the
gross production. The rate of royalties payable generally depends in part on prescribed
reference prices, well productivity, geographical location, field discovery date and the
type or quality of the petroleum product produced.

From time to time the governments of the western Canadian provinces
create incentive programs for exploration and development. Such programs often provide for
royalty rate reductions, royalty holidays and tax credits, and are generally introduced
when commodity prices are low. The programs are designed to encourage exploration and
development activity by improving earnings and cash flow within the industry.

In the Province of Alberta, a producer of oil or natural gas is
entitled to a credit against the royalties payable to the Crown by virtue of the Alberta
Royalty Tax Credit or, ARTC program. The ARTC rate is based on a price sensitive formula
and the ARTC rate varies between 75% at prices at and below $100 per thousand cubic metres
and 25% at prices at and above $210 per thousand cubic metres. The ARTC rate is applied to
a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated
group of producers. Crown royalties on production from producing properties acquired from
a corporation claiming maximum entitlement to ARTC will generally not be eligible for
ARTC. The rate will be established quarterly based on the average "par price",
as determined by the Alberta Department of Energy for the previous quarterly period.

On December 22, 1997, the Alberta government announced that it was
conducting a review of the ARTC program with the objective of setting out better-targeted
objectives for a smaller program and to deal with administrative difficulties. On August
30, 1999, the Alberta government announced that it would not be reducing the size of the
program but that it would introduce new rules to reduce the number of persons who qualify
for the program. The new rules will preclude companies that pay less than $10,000 in
royalties per year and non-corporate entities from qualifying for the program. Such rules
will not presently preclude Enterra from being eligible for the ARTC program.

Crude oil and natural gas royalty holidays for specific wells and
royalty reductions reduce the amount of Crown royalties paid by Enterra to the provincial
governments. In general, the ARTC program provides a rebate on Alberta Crown royalties
paid in respect of eligible producing properties.



-23-

Land Tenure

Crude oil and natural gas located in the western provinces is owned
predominantly by the respective provincial governments. Provincial governments grant
rights to explore for and produce oil and natural gas pursuant to leases, licences and
permits for varying terms from two years and on conditions set forth in provincial
legislation including requirements to perform specific work or make payments. Oil and
natural gas located in such provinces can also be privately owned and rights to explore
for and produce such oil and natural gas are granted by lease on such terms and conditions
as may be negotiated.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental
regulations pursuant to a variety of provincial and federal legislation. Such legislation
provides for restrictions and prohibitions on the release or emission of various
substances produced in association with certain oil and gas industry operations. In
addition, such legislation requires that well and facility sites be abandoned and
reclaimed to the satisfaction of provincial authorities. Compliance with such legislation
can require significant expenditures and a breach of such requirements may result in
suspension or revocation of necessary licenses and authorizations, civil liability for
pollution damage and the imposition of material fines and penalties.

Environmental legislation in the Province of Alberta has been
consolidated into the Environmental Protection and Enhancement Act, or EPEA, which
came into force on September 1, 1993. The EPEA imposes stricter environmental standards,
requires more stringent compliance, reporting and monitoring obligations and significantly
increases penalties for violations. Enterra is committed to meeting its responsibilities
to protect the environment wherever it operates and anticipates making increased
expenditures of both a capital and expense nature as a result of the increasingly
stringent laws relating to the protection of the environment and will be taking such steps
as required to ensure compliance with the EPEA and similar legislation in other
jurisdictions in which it operates. Enterra believes that it is in material compliance
with applicable environmental laws and regulations. Enterra also believes that it is
reasonably likely that the trend towards stricter standards in environmental legislation
and regulation will continue.



Income Streams and Distribution Policy

A portion of the cash flows generated by the assets held, directly or
indirectly, by the Trust is distributed to holders of trust units. The Trustee may, in
respect of any period, declare payable to the unitholders all or any part of the net
income of the Trust, less all expenses and liabilities of the Trust due and accrued and
which are chargeable to the net income of the Trust.

The New Enterra Board currently intends to provide all unitholders with
monthly cash distributions of approximately USD $0.10 per trust unit. However, the
availability of cash flows for the payment of distributions will at all times be dependant
upon a number of factors, including resource prices, production rates and reserve growth
and the New Enterra Board cannot assure that cash flows will be available for distribution
to unitholders in the amounts anticipated or at all. See "Risk Factors".

Our primary sources of cash flow is payments from New Enterra of
interest on the principal amount of the Series A Notes and payments from EEC Trust of
interest on the principal amount of the CT Note.

The Series A Notes

Pursuant to the Arrangement, New Enterra issued the Series A Notes to
the Trust. The principal amount of the Series A Notes issued is $125,000,000. The Series A
Notes are unsecured and bear interest from the date of issue at 14% per annum. Interest is
payable for each month during the term on the 15th day of the month following such month.

CT Note

The CT Note is a subordinated, demand participating promissory note.
The CT Note bears interest at a rate that will be re-set from time to time so as to
approximate the return on the shares of New Enterra held by EEC Trust. Redemptions and
returns of capital on shares of New Enterra held by EEC Trust may be required to be
applied as prepayments of the principal balance of the CT Note.



- 24 -



An unlimited number of trust units may be created and issued pursuant
to the Trust Indenture. Each trust unit entitles the holder thereof to one vote at any
meeting of the holders of trust units and represents an equal fractional undivided
beneficial interest in any distribution from the Trust (whether of net income, net
realized capital gains or other amounts) and in any net assets of the Trust in the event
of termination or winding up of the Trust. All trust units rank among themselves equally
and rateably without discrimination, preference or priority. Each trust unit is
transferable, is not subject to any conversion or pre-emptive rights and entitles the
holder thereof to require the Trust to redeem any or all of the trust units held by such
holder (see "Redemption Right") and to one vote at all meetings of
unitholders for each trust unit held. In addition, in certain circumstances unitholders
will have the right to instruct the trustees of EEC Trust with respect to the voting of
shares of New Enterra held by EEC Trust at meetings of holders of shares of New Enterra.
See "Meetings of Unitholders" and "Exercise of Voting Rights".

The trust units do not represent a traditional investment and should
not be viewed by investors as "shares" in either New Enterra, or the Trust. As
holders of trust units in the Trust, unitholders will not have the statutory rights
normally associated with ownership of shares of a corporation including, for example, the
right to bring "oppression" or "derivative" actions.

The price per trust unit is a function of anticipated distributable
income generated by New Enterra and the ability of New Enterra to effect long term growth
in the value of the Trust. The market price of the trust units is sensitive to a variety
of market conditions including, but not limited to, interest rates, commodity prices and
the ability of New Enterra to acquire additional assets. Changes in market conditions may
adversely affect the trading price of the trust units.

The trust units are not "deposits" within the meaning of the
Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions
of that Act or any other legislation. Furthermore, the Trust is not a trust company and,
accordingly, is not registered under any trust and loan company legislation as it does not
carry on or intend to carry on the business of a trust company.

Special Voting Rights

The Trust Indenture allows for the creation of Special Voting Rights
which will enable the Trust to provide voting rights to holders of Exchangeable Shares
and, in the future, to holders of other exchangeable shares that may be issued by New
Enterra or other subsidiaries of the Trust in connection with other exchangeable share
transactions.

Holders of Special Voting Rights are not be entitled to any
distributions of any nature whatsoever from the Trust and each holder shall be entitled to
attend at meetings of unitholders and, subject to the terms of the instrument creating the
Special Voting Rights, is entitled to that number of votes equal to the number of votes
attached to the trust units for which the Special Voting Rights held by such holder are
exchangeable, exercisable or convertible. Holders of Special Voting Rights are also be
entitled to receive all notices, communications or other documentation required to be
given or otherwise sent to holders of trust units. Except for the right to attend and vote
at meetings of unitholders and receive notices, communications and other documentation
sent to unitholders, the Special Voting Rights do not confer upon the holders thereof any
other rights.

Under the terms of the Voting and Exchange Trust Agreement, the Trust
has issued a Special Voting Right to the Voting and Exchange Trust Agreement Trustee for
the benefit of every person who received Exchangeable Shares pursuant to the Arrangement.

Unitholder Limited Liability

The Trust Indenture provides that no unitholder, in its capacity as
such, shall incur or be subject to any liability in contract or in tort in connection with
the Trust or its obligations or affairs and, in the event that a court determines
unitholders are subject to any such liabilities, the liabilities will be enforceable only
against, and will be satisfied only out of the Trust's assets. Pursuant to the Trust
Indenture, the Trust will indemnify and hold harmless each unitholder from any costs,
damages, liabilities, expenses, charges or losses suffered by a unitholder from or arising
as a result of such unitholder not having such limited liability.

The Trust Indenture provides that all contracts signed by or on behalf
of the Trust must contain a provision to the effect that such obligation will not be
binding upon unitholders personally. Notwithstanding the terms of the Trust Indenture,
unitholders may not be protected from liabilities of the Trust to the same extent a
shareholder is protected from the liabilities of a corporation. Personal liability may
also arise in respect of claims against the Trust (to the extent that claims are not
satisfied by the Trust) that do not arise under contracts, including claims in tort,
claims for taxes and possibly certain other statutory liabilities. The possibility of any
personal liability to unitholders of this nature arising is considered unlikely in view of
the fact that the sole activity of the Trust is to hold securities, and all of the
business operations are carried on by New Enterra, directly or indirectly.



- 25 -

The activities of the Trust, the EEC Trust, New Enterra and the
Partnership is conducted, upon the advice of counsel, in such a way and in such
jurisdictions as to avoid as far as possible any material risk of liability to the
unitholders for claims against the Trust including by obtaining appropriate insurance,
where available, for the operations of New Enterra and having contracts signed by or on
behalf of the Trust include a provision that such obligations are not binding upon
unitholders personally.

Redemption Right

Trust units are redeemable at any time on demand by the holders thereof
upon delivery to the transfer agent of the Trust of the certificate or certificates
representing such trust units, accompanied by a duly completed and properly executed
notice requiring redemption. Upon receipt of the notice to redeem trust units by the
transfer agent, the holder thereof shall only be entitled to receive a price per trust
unit (the "Market Redemption Price") equal to the lesser of: (i) 90% of the
"market price" of the trust units on the principal market on which the trust
units are quoted for trading during the 10 trading day period commencing immediately after
the date on which the trust units are tendered to the Trust for redemption; and (ii) the
closing market price on the principal market on which the trust units are quoted for
trading on the date that the trust units are so tendered for redemption. Where more than
one market exists for the trust units, the principal market shall mean the market on which
the trust units experience the greatest volume of trading activity on the date or for the
period in question, as applicable.

For the purposes of this calculation, "market price" is an
amount equal to the simple average of the closing price of the trust units for each of the
trading days on which there was a closing price; provided that, if the applicable exchange
or market does not provide a closing price but only provides the highest and lowest prices
of the trust units traded on a particular day, the market price shall be an amount equal
to the simple average of the average of the highest and lowest prices for each of the
trading days on which there was a trade; and provided further that if there was trading on
the applicable exchange or market for fewer than five of the 10 trading days, the market
price shall be the simple average of the following prices established for each of the 10
trading days: the average of the last bid and last ask prices for each day on which there
was no trading; the closing price of the trust units for each day that there was trading
if the exchange or market provides a closing price; and the average of the highest and
lowest prices of the trust units for each day that there was trading, if the market
provides only the highest and lowest prices of trust units traded on a particular day. The
closing market price is: an amount equal to the closing price of the trust units if there
was a trade on the date; an amount equal to the average of the highest and lowest prices
of the trust units if there was trading and the exchange or other market provides only the
highest and lowest prices of trust units traded on a particular day; and the average of
the last bid and last ask prices if there was no trading on the date.

The aggregate Market Redemption Price payable by the Trust in respect
of any trust units surrendered for redemption during any calendar month shall be satisfied
by way of a cash payment on the last day of the following month. The entitlement of
unitholders to receive cash upon the redemption of their trust units is subject to the
limitation that the total amount payable by the Trust in respect of such trust units and
all other trust units tendered for redemption in the same calendar month and in any
preceding calendar month during the same year shall not exceed $100,000; provided that New
Enterra may, in its sole discretion, waive such limitation in respect of any calendar
month. If this limitation is not so waived, the Market Redemption Price payable by the
Trust in respect of trust units tendered for redemption in such calendar month shall be
paid on the last day of the following month as follows: (i) firstly, by the Trust
distributing Series A Notes having an aggregate principal amount equal to the aggregate
Market Redemption Price of the trust units tendered for redemption, and (ii) secondly, to
the extent that the Trust does not hold Series A Notes having a sufficient principal
amount outstanding to effect such payment, by the Trust issuing its own promissory notes
to the unitholders who exercised the right of redemption having an aggregate principal
amount equal to any such shortfall (herein referred to as "Redemption Notes").
Notwithstanding the foregoing, the distribution of any Series A Notes and the issuance of
any Redemption Notes shall be conditional upon the receipt of all necessary regulatory
approvals and the making of all necessary governmental registrations, declarations and
filings, including, without limitation, any required registration of the Series A Notes or
Redemption Notes, as applicable, to be distributed or issued in respect of the payment of
the Market Redemption Price, and any required qualification of the Trust Indenture
relating to such Series A Notes or Redemption Notes, under the securities laws of the
United States.



- 26 -

If at the time trust units are tendered for redemption by a unitholder,
(i) the outstanding trust units are not listed for trading on the TSX or Nasdaq and are
not traded or quoted on any other stock exchange or market which New Enterra considers, in
its sole discretion, provides representative fair market value price for the trust units,
or (ii) trading of the outstanding trust units is suspended or halted on any stock
exchange on which the trust units are listed for trading or, if not so listed, on any
market on which the trust units are quoted for trading, on the date such trust units are
tendered for redemption or for more than five trading days during the 10 trading day
period, commencing immediately after the date such trust units were tendered for
redemption then such unitholder shall, instead of the Market Redemption Price, be entitled
to receive a price per trust unit (the "Appraised Redemption Price") equal to
90% of the fair market value thereof as determined by New Enterra as at the date on which
such trust units were tendered for redemption. The aggregate Appraised Redemption Price
payable by the Trust in respect of trust units tendered for redemption in any calendar
month shall be paid on the last day of the third following month by, at the option of the
Trust: (i) a cash payment; or (ii) a distribution of Series A Notes and/or Redemption
Notes as described above.

It is anticipated that this redemption right will not be the primary
mechanism for holders of trust units to dispose of their trust units. Series A Notes or
Redemption Notes which may be distributed in specie to unitholders in connection with a
redemption will not be listed on any stock exchange and no market is expected to develop
in such Series A Notes or Redemption Notes. Series A Notes or Redemption Notes may not be
qualified investments for trusts governed by registered retirement savings plans,
registered retirement income funds, deferred profit sharing plans and registered education
savings plans.

Meetings of Unitholders

The Trust Indenture provides that meetings of unitholders must be
called and held for, among other matters, the election or removal of the Trustee, the
appointment or removal of the auditors of the Trust, the approval of amendments to the
Trust Indenture (except as described under "Amendments to the Trust Indenture"),
the sale of the property of the Trust as an entirety or substantially as an entirety, and
the commencement of winding up the affairs of the Trust.

A meeting of unitholders may be convened at any time and for any
purpose by the Trustee and must be convened, except in certain circumstances, if
requisitioned in writing by (i) New Enterra or (ii) the holders of trust units and Special
Voting Rights holding in aggregate not less than 5% of the votes entitled to be voted at a
meeting of unitholders. A requisition must, among other things, state in reasonable detail
the business purpose for which the meeting is to be called.

Unitholders may attend and vote at all meetings of unitholders either
in person or by proxy and a proxyholder need not be a unitholder. Two persons present in
person or represented by proxy and representing in the aggregate at least 5% of the votes
attaching to all outstanding trust units shall constitute a quorum for the transaction of
business at all such meetings. For the purposes of determining such quorum, the holders of
any issued Special Voting Rights who are present at the meeting shall be regarded as
representing outstanding trust units equivalent in number to the votes attaching to such
Special Voting Rights.

The Trust Indenture contains provisions as to the notice required and
other procedures with respect to the calling and holding of meetings of unitholders in
accordance with the requirements of applicable laws.

Voting Of EEC trust units

There will be a meeting of the holders of EEC trust units immediately
following each meeting of unitholders for the purpose of directing the Trustee as to the
manner in which the Trustee shall vote the EEC trust units held by the Trust in respect of
those matters voted on at such meeting of unitholders. Any resolution passed by
unitholders pertaining to the manner in which EEC trust units held by the Trust are to be
voted by the Trustee in respect of a particular matter which is to be put forth to the
holders of EEC trust units for vote at a contemplated meeting (including by written
resolution) of holders of EEC trust units, shall be deemed to be a direction to the
Trustee in respect of the EEC trust units held by the Trust to, as applicable, either vote
such EEC trust units in favour of or in opposition to, or to vote or with-hold from voting
in respect of such matter in equal proportions to the votes cast by unitholders in respect
of the matter, and the Trustee is obligated to vote, in respect of such matter if put
forth to the holders of EEC trust units at a meeting of such holders, the EEC trust units
held by the Trust in accordance with such direction.

Exercise of Voting Rights



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The Trustee is prohibited from authorizing or approving:

> (a) any sale, lease or other disposition of, or any interest in, all or
>     substantially all of the assets owned, directly or indirectly, by the Trust, except in
>     conjunction with an internal reorganization of the direct or indirect assets of the Trust,
>     as a result of which the Trust has substantially the same interest, whether direct or
>     indirect, in the assets as the interest, whether direct or indirect, that it had prior to
>     the reorganization;
>     (b) any merger, amalgamation, arrangement, reorganization,
>     recapitalization, business combination or similar transaction involving the Trust and any
>     other corporation, except in conjunction with an internal reorganization as referred to in
>     paragraph (a) above; or
>     (c) the winding up, liquidation or dissolution of the Trust prior to
>     the end of the term of the Trust except in conjunction with an internal reorganization as
>     referred to in paragraph (a) above;

without the prior approval of the unitholders by Special Resolution at
a meeting of unitholders called for that purpose.

In addition, the Trustee is prohibited from authorizing EEC Trust to
vote any shares of New Enterra in respect of:

> (a) any sale, lease or other disposition of, or any interest in, all or
>     substantially all of the assets owned, directly or indirectly, by Enterra, the Trust or
>     the Partnership, except in conjunction with an internal reorganization of the direct or
>     indirect assets of New Enterra, EEC Trust or the Partnership, as the case may be, as a
>     result of which EEC Trust has substantially the same interest, whether direct or indirect,
>     in the assets as the interest, whether direct or indirect, that it had prior to the
>     reorganization;
>     (b) any merger, amalgamation, arrangement, reorganization,
>     recapitalization, business combination or similar transaction involving New Enterra, EEC
>     Trust or the Partnership and any other corporation, except in conjunction with an internal
>     reorganization as referred to in paragraph (a) above;
>     (c) the winding up, liquidation or dissolution of New Enterra, EEC
>     Trust or the Partnership prior to the end of the term of EEC Trust, except in conjunction
>     with an internal reorganization as referred to in paragraph (a) above;
>     (d) any amendment to the articles of New Enterra to increase or
>     decrease the minimum or maximum number of directors;
>     (e) any material amendments to the articles of New Enterra to change
>     the authorized share capital or amend the rights, privileges, restrictions and conditions
>     attaching to any class of New Enterra's shares in a manner which may be prejudicial to EEC
>     Trust; or
>     (f) any material amendment to the CT Indenture or the Partnership
>     Agreement which may be prejudicial to EEC Trust;

without the prior approval of the unitholders by Special Resolution at
a meeting of unitholders called for that purpose.

Finally, the Trustee is prohibited from authorizing EEC Trust to vote
any shares of New Enterra with respect to any matter which under applicable law (including
policies of Canadian securities commissions) or applicable stock exchange rules would
require the approval of the holders of shares of New Enterra by ordinary resolution or
special resolution, without the prior approval of the unitholders by Ordinary Resolution
or Special Resolution, as the case may be.

Trustee

Olympia Trust Company is the initial trustee of the Trust. The Trustee
is responsible for, among other things, accepting subscriptions for trust units and
issuing trust units pursuant thereto, maintaining the books and records of the Trust and
providing timely reports to holders of trust units. The Trust Indenture provides that the
Trustee shall exercise its powers and carry out its functions thereunder as Trustee
honestly, in good faith and in the best interests of the Trust and the unitholders and, in
connection therewith, shall exercise that degree of care, diligence and skill that a
reasonably prudent trustee would exercise in comparable circumstances.



- 28 -

The initial term of the Trustee's appointment is until the third annual
meeting of unitholders. The unitholders shall, at the third annual meeting of unitholders,
re-appoint, or appoint a successor to the Trustee for an additional three year term, and
thereafter, the unitholders shall reappoint or appoint a successor to the Trustee at the
annual meeting of unitholders three years following the reappointment or appointment of
the successor to the Trustee. The Trustee may also be removed by Special Resolution of the
unitholders. Such resignation or removal becomes effective upon the acceptance or
appointment of a successor trustee.

Delegation of Authority, Administration and Trust Governance

The New Enterra Board has generally been delegated the significant
management decisions of the Trust. In particular, the Trustee has delegated to New Enterra
responsibility for any and all matters relating to the following: (i) an offering of
securities of the Trust; (ii) ensuring compliance with all applicable laws, including in
relation to an offering of securities of the Trust; (iii) all matters relating to the
content of any offering documents, the accuracy of the disclosure contained therein and
the certification thereof; (iv) all matters concerning the terms of, and amendment from
time to time of the material contracts of the Trust; (v) all matters concerning any
underwriting or agency agreement providing for the sale of trust units or rights to trust
units; (vi) all matters relating to the redemption of trust units; (vii) all matters
relating to the voting rights on any instruments held by the Trust, other than the EEC
trust units; and (viii) all matters relating to the specific powers and authorities as set
forth in the Trust Indenture.

Liability of The Trustee

The Trustee, its directors, officers, employees, shareholders and
agents is not be liable to any unitholder or any other person, in tort, contract or
otherwise, in connection with any matter pertaining to the Trust or the property of the
Trust, arising from the exercise by the Trustee of any powers, authorities or discretion
conferred under the Trust Indenture, including, without limitation, any action taken or
not taken in good faith in reliance on any documents that are, prima facie, properly
executed, any depreciation of, or loss to, the property of the Trust incurred by reason of
the sale of any asset, any inaccuracy in any evaluation provided by any other
appropriately qualified person, any reliance on any such evaluation, any action or failure
to act of New Enterra, or any other person to whom the Trustee has, with the consent of
New Enterra, delegated any of its duties hereunder, or any other action or failure to act
(including failure to compel in any way any former trustee to redress any breach of trust
or any failure by New Enterra to perform its duties under or delegated to it under the
Trust Indenture or any other contract), unless such liabilities arise out of the gross
negligence, wilful default or fraud of the Trustee or any of its directors, officers,
employees or shareholders. If the Trustee has retained an appropriate expert, adviser or
legal counsel with respect to any matter connected with its duties under the Trust
Indenture, the Trustee may act or refuse to act based on the advice of such expert,
adviser or legal counsel, and the Trustee shall not be liable for and shall be fully
protected from any loss or liability occasioned by any action or refusal to act based on
the advice of any such expert, adviser or legal counsel. In the exercise of the powers,
authorities or discretion conferred upon the Trustee under the Trust Indenture, the
Trustee is and shall be conclusively deemed to be acting as Trustee of the assets of the
Trust and shall not be subject to any personal liability for any debts, liabilities,
obligations, claims, demands, judgments, costs, charges or expenses against or with
respect to the Trust or the property of the Trust. In addition, the Trust Indenture
contains other customary provisions limiting the liability of the Trustee.

Amendments to The Trust Indenture

The Trust Indenture may be amended or altered from time to time by
special resolution of the unitholders. The Trustee may, without the approval of any of the
unitholders, amend the Trust Indenture for the purpose of:

> (a) ensuring the Trust's continuing compliance with applicable laws or
>     requirements of any governmental agency or authority;
>     (b) ensuring that the Trust will satisfy the provisions of each of
>     subsections 108(2) and 132(6) and paragraph 132(8)(a) of the Tax Act as from time to time
>     amended or replaced;
>     (c) providing for and ensuring (i) the allocation of items of income,
>     gain, loss, deduction and credit in respect of the Trust for United States federal income
>     tax purposes; (ii) the filing of income tax returns necessary or desirable for the
>     purposes of United States federal income tax; or (iii) compliance by the Trust with any
>     other applicable provisions of United States federal income tax law;
>     (d) ensuring that such additional protection is provided for the
>     interests of unitholders as the Trustee may consider expedient;
>     
>     - 29 -
>     (e) removing or curing any conflicts or inconsistencies between the
>     provisions of the Trust Indenture or any supplemental indenture and any other agreement of
>     the Trust or any offering document pursuant to which securities of the Trust are issued
>     with respect to the Trust, or any applicable law or regulation of any jurisdiction,
>     provided that in the opinion of the Trustee the rights of the Trustee and of the
>     unitholders are not prejudiced thereby;
>     (f) curing, correcting or rectifying any ambiguities, defective or
>     inconsistent provisions, errors, mistakes or omissions, provided that in the opinion of
>     the Trustee the rights of the Trustee and of the unitholders are not prejudiced thereby;
>     and
>     (g) changing the situs of or the laws governing the Trust which, in the
>     opinion of the Trustee, is desirable in order to provide unitholders with the benefit of
>     any legislation limiting their liability.

Termination of the Trust

Unitholders may vote to terminate the Trust at any meeting of
unitholders duly called for that purpose, subject to the following: (a) a vote may only be
held if requested in writing by the holders of not less than 20% of the outstanding trust
units; (b) a quorum of 50% of the issued and outstanding trust units is present in person
or by proxy; and (c) the termination must be approved by special resolution of
unitholders.

Unless the Trust is earlier terminated or extended by vote of the
unitholders, the Trust shall continue in full force and effect for a period which shall
end twenty-one years after the date of death of the last surviving issue of Her Majesty,
Queen Elizabeth II. In the event that the Trust is wound up, the Trustee will sell and
convert into money the property of the Trust in one transaction or in a series of
transactions at public or private sale and do all other acts appropriate to liquidate the
property of the Trust in accordance with any applicable laws or requirements of any
governmental agency or authority, and shall in all respects act in accordance with the
directions, if any, of the unitholders in respect of termination authorized pursuant to
the special resolution of the unitholders authorizing the termination of the Trust. After
paying, retiring or discharging or making provision for the payment, retirement or
discharge of all known liabilities and obligations of the Trust and providing for
indemnity against any other outstanding liabilities and obligations, the Trustee shall
distribute the remaining part of the proceeds of the sale of the assets together with any
cash forming part of the property of the Trust among the unitholders in accordance with
their pro rata interests.

Reporting to Unitholders

The financial statements of the Trust are audited annually by an
independent recognized firm of chartered accountants. The audited financial statements of
the Trust, together with the report of such chartered accountants, will be mailed by the
Trustee to unitholders and the unaudited interim financial statements of the Trust will be
mailed to unitholders within the periods prescribed by securities legislation. The year
end of the Trust shall be December 31. The Trust is subject to the continuous disclosure
obligations under all applicable securities legislation.

The Trust is subject to the reporting requirements of the 1934 Act
applicable to foreign private issuers, and in connection therewith will file or submit
reports, including annual reports and other information with the U.S. Securities and
Exchange Commission (the "SEC"). Such reports and other information can be
inspected and copied at the public reference facilities maintained by the SEC at 450 Fifth
Street, N.W., Room 1024, Judiciary Plaza, Washington, D.C. The Trust's SEC filings and
submissions will also be available to the public on the SEC's web site at
http://www.sec.gov.



- 30 -

ITEM 5. Operating and Financial Review and Prospects

MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following managements discussion and analysis of Enterra
Energy Trust ("Enterra or the Trust") is as of April 16, 2004 and should be read
in conjunction with the audited consolidated financial statements of the Trust for the
years ended December 31, 2003 and 2002, together with accompanying notes, which have been
prepared in accordance with Canadian generally accepted accounting principles. The
significant differences to generally accepted accounting principles of the United States
of America are as set out in note 17. Discussion with regard to the Trusts 2004
outlook is based on currently available information. All amounts are stated in Canadian
dollars except where otherwise indicated. Natural gas volumes have been converted to a
crude oil equivalent using a ratio of 6 mcf to 1 bbl of oil.

Cash flow, expressed before changes in non-cash working capital, is
used by Enterra to measure and evaluate operating performance and liquidity. Earnings from
operations, which is calculated before income taxes and before gains or losses on disposal
of assets, is used by Enterrra to measure and evaluate operating performance. Cash flow
and earnings from operations do not have any standardized meaning prescribed by the
Canadian Generally Accepted Accounting Principles ("GAAP") and therefore may not
be comparable with the calculation of similar measures for other companies.

It is managements view, based on its communications with
investors during events like conference calls, webcasts or road shows, that these non-GAAP
measures are most relevant to our investors and unitholders, especially since
Enterras conversion to an oil and gas income trust. Earnings from operations,
because it excludes one-time non-recurring events, can provide investors with an
undistorted frame of reference when comparing performance from year to year or quarter to
quarter. Cash flow from operations is also extremely relevant to investors because it is
the starting point for setting the monthly distribution level.

Both cash flow from operations and earnings from operations are reconciled to GAAP
earnings in tables included in the management discussion and analysis section.

Special Note Regarding Forward-Looking Statements

This annual report includes forward-looking statements. All statements
other than statements of historical facts contained in this annual report, including
statements regarding our future financial position, business strategy and plans and
objectives of management for future operations, are forward-looking statements. The words
"believe," "may," "will," "estimate,"
"continue," "anticipate," "intend," "should,"
"plan," "expect" and similar expressions, as they relate to us, are
intended to identify forward-looking statements. We have based these forward-looking
statements largely on our current expectations and projections about future events and
financial trends that we believe may affect our financial condition, results of
operations, business strategy and financial needs. These forward-looking statements are
subject to a number of risks, uncertainties and assumptions described in "Risk
Factors" and elsewhere in this annual report.

Other sections of this annual report may include additional factors
which could adversely affect our business and financial performance. Moreover, we operate
in a very competitive and rapidly changing environment. New risk factors emerge from time
to time and it is not possible for our management to predict all risk factors, nor can we
assess the impact of all factors on our business or the extent to which any factor, or
combination of factors, may cause actual results to differ materially from those contained
in any forward-looking statements.

We undertake no obligation to update publicly or revise any
forward-looking statements. You should not rely upon forward-looking statements as
predictions of future events or performance. We cannot assure you that the events and
circumstances reflected in the forward-looking statements will be achieved or occur.
Although we believe that the expectations reflected in the forward-looking statements are
reasonable, we cannot guarantee future results, levels of activity, performance or
achievements.

Critical Accounting Policies

The Company follows the full cost method of accounting for oil and
natural gas properties and equipment whereby we capitalize all costs relating to its
acquisition of, exploration for and development of oil and natural gas reserves.
Enterras consolidated financial condition and results of operations are sensitive
to, and may be adversely affected by, a number of subjective or complex judgments relating
to methods, assumptions or estimates required under the full cost method of accounting
concerning the effect of matters that are inherently uncertain. For example:



- 31 -

> (i) Capitalized costs under the full cost method are generally depleted
>     and depreciated using the unit-of-production method, based on estimated proved oil and gas
>     reserves as determined by independent engineers. In addition, capital costs are also
>     restricted from exceeding the sum of the estimated future net revenues of those
>     properties, plus the cost or estimated fair value of unproved properties less estimated
>     future abandonment and site restoration costs, general administrative expenses, financing
>     costs and income taxes (the "ceiling test"). Should this comparison indicate an
>     excess carrying value, a write-down would be recorded. To economically evaluate the
>     Enterras proved oil and natural gas reserves, these independent engineers must
>     necessarily make a number of assumptions, estimates and judgments that they believe to be
>     reasonable based upon their expertise and professional and CICA and SEC guidelines. Were
>     the independent engineers to use differing assumptions, estimates and judgments, then
>     Enterras consolidated financial condition and results of operations would be
>     affected. For example, Enterra would have lower revenues and net profits (or higher net
>     losses) in the event the revised assumptions, estimates and judgments resulted in lower
>     reserve estimates, since our depletion and depreciation rate would then be higher and it
>     might also result in a write-down under the ceiling test. Similarly, Enterra would have
>     higher revenues and net profits (or lower net losses) in the event the revised
>     assumptions, estimates and judgments resulted in higher reserve estimates.
>     (ii) Enterras management also periodically assesses the carrying
>     values of unproved properties to ascertain whether any impairment in value has occurred.
>     This assessment typically includes a determination of the anticipated future net cash
>     flows based upon reserve potential and independent appraisal where warranted. Impairment
>     is recorded if this assessment indicates the future potential net cash flows are less than
>     the capitalized costs. Were Enterras management to use differing assumptions,
>     estimates and judgments, then Enterras consolidated financial condition and results
>     of operations would be affected. For example, Enterra would have lower net profits (or
>     higher net losses) in the event the revised assumptions, estimates and judgments resulted
>     in increased impairment expense.
>     (iii) Estimated future restoration costs are provided for using the
>     unit of production method based on estimated gross proved reserves. Costs are estimated by
>     our engineers based on current regulations, costs, technology and industry standards. The
>     annual charge is recorded as a provision for future site restoration and abandonment
>     costs. Removal and site restoration expenditures are charged to the accumulated provision
>     as incurred.

Results of Operations 2003 compared to 2002

Overview

Enterra managed to achieve record revenue, cash flow and earnings in
2003 while converting itself to an oil and gas income trust during the fourth quarter.
Cash flow from operations, excluding the one-time re-organization costs of $5.8 million,
was in excess of $36 million for the year or $1.92 on a per unit basis. As a trust,
Enterra established its initial monthly distribution level at US$0.10 per unit. The first
distribution was paid on January 15, 2004 for the month of December 2003. Enterra drilled
47 wells in 2003, including 20 wells at Clair and 19 wells at Sylvan Lake. The two
projects represented almost 60% of Enterras 2003 capital expenditures. The 2003
drilling program resulted in 31 oil wells (31.0 net) and 3 gas wells (1.1 net) for an 86%
success rate.

Summarized financial and
    operational data (in Thousands except for volumes and per unit/ share amounts)Q4
    2003
    Q4
    2002
    Change
    Year
    2003
    Year
    2002
    ChangeExit production rate (boe per day)
    6,460
    5,335
    + 21%
    6,460
    5,335
    + 21%Average production revenue
    $15,598
    $10,060
    + 55%
    $72,097
    $25,746
    +180%Average production volumes (boe per day)
    5,206
    3,221
    + 62%
    5,024
    2,320
    +117%Cash flow from operations (1) (3)
    $ 7,467
    $ 4,851
    + 54%
    $36,455
    $11,950
    +205%Cash flow from operations per unit/share (1)
    (3)
    $ 0.37
    $ 0.26
    + 40%
    $ 1.92
    $ 0.65
    +195%Earnings from operations (2) (3)
    $1,019
    $ 1,108
    - 8%
    $12,835
    $ 2,909
    +341%Earnings from operations per unit/share (2)
    (3)
    $ 0.05
    $ 0.06
    - 17%
    $ 0.68
    $ 0.16
    +326%Average number of units outstanding (after
    giving effect to trust conversion)
    20,205
    18,337
    + 10%
    18,954
    18,309
    + 4%Average price per bbl of oil
    $ 31.78
    $ 34.93
    - 9%
    $ 39.12
    $ 33.86
    + 16%Average price per mcf of natural gas
    $ 5.91
    $ 5.34
    + 11%
    $ 6.65
    $ 4.08
    + 63%Operating costs per boe
    $ 6.19
    $ 7.88
    - 21%
    $ 6.96
    $ 7.11
    - 2%General and
    administrative expenses per boe (cash portion)
    $ 1.59
    $ 1.71
    - 7%
    $ 1.69
    $ 1.99
    - 15%(1)Excluding
    re-organization costs of $5.8 million in year and Q4, 2003(2)Excluding income taxes,
    re-organization costs of $5.8 million in 2003 and $3.1 million gain on redemption of
    preferred shares in 2002(3)Both
    cash flow from operations and earnings from operations are non-GAAP measures. It is
    managements view that this information is relevant for investors in order to compare
    2003 with 2002 without the impact of one-time non-recurring events. Both cash flow from
    operations and earnings from operations are reconciled to GAAP earnings in the earnings
    and cash flow sections of the management discussion and analysis.


- 32 -

QUARTERLY INFORMATION

Quarterly information (In
    Thousands, except per unit/ share data)Q1
    2003
    Q1
    2002
    
    Q2
    2003
    Q2
    2002
    
    Q3
    2003
    Q3
    2002
    
    Q4
    2003
    Q4
    2002Revenue
    $ 22,002
    $ 5,598
    
    $ 18,484
    $ 5,051
    
    $ 16,012
    $ 5,036
    
    $ 15,598
    $ 10,060Income from operations
    $ 7,192
    $ 326
    
    $ 2,699
    $ 620
    
    $ 1,924
    $ 854
    
    $ 1,019
    $ 1, 108Per unit/share, basic
    $ 0.39
    $ 0.02
    
    $ 0.15
    $ 0.03
    
    $ 0.10
    $ 0.04
    
    $ 0.04
    $ 0.06Per unit/share, diluted
    $ 0.37
    $ 0.02
    
    $ 0.14
    $ 0.03
    
    $ 0.09
    $ 0.04
    
    $ 0.08
    $ 0.05Net earnings
    $ 4,186
    $ 3,150
    
    $ 4,965
    $ 398
    
    $ 956
    $ 714
    
    $ (5,104)
    $ 715Per unit/share, basic
    $ 0.23
    $ 0.17
    
    $ 0.27
    $ 0.02
    
    $ 0.05
    $ 0.04
    
    $ ( 0.28)
    $ 0.04Per
    unit/share, diluted
    $ 0.21
    $ 0.17
    
    $ 0.25
    $ 0.02
    
    $ 0.05
    $ 0.04
    
    $ ( 0.25)
    $ 0.03




Summarized
    financial and operational data (in Thousands except for volumes and per
    unit/share amounts)Year
    2003
    Year
    2002
    Year
    2001Revenue
    $72,097
    $25,746
    $20,264Cash flow from operations (1)
    (4)
    $36,455
    $11,950
    $ 9,810Cash flow from operations per
    unit/share  basic  (1)
    $ 1.92
    $ 0.65
    $ 0.70Cash flow from operations per
    unit/share  diluted (1)
    $ 1.92
    $ 0.63
    $ 0.70Earnings from operations (2)
    (4)
    $12,835
    $ 2,909
    $ 3,228Earnings from operations per
    unit/share  -  basic   (2)
    $ 0.68
    $ 0.16
    $ 0.23Earnings from operations per
    unit/share - diluted (2)
    $ 0.68
    $ 0.15
    $ 0.23Net earnings
    $ 5,004
    $ 4,977
    $ 1,617Net earnings per unit/share  
    -  basic
    $ 0.26
    $ 0.27
    $ 0.12Net earnings per unit/share -
    diluted
    $ 0.26
    $ 0.27
    $ 0.12Average number of units
    outstanding (after giving effect to trust conversion)
    18,954
    18,309
    13,985Total assets
    $ 116,230
    $ 102,717
    $ 80,063Total long-term debt (including
    bank debt and capital leases)
    $ 38,128
    $ 29,358
    $18,409Distribution
    per unit (3)
    US$ 0.10
    N/A
    N/A(1)Excluding
    re-organization costs of $5.8 million in year and Q4, 2003(2)
    Excluding income taxes, re-organization costs of $5.8 million in 2003,$3.1 million gain on
    redemption of preferred shares in 2002 and $929,037 in restructuring charges in 2001(3)Only
    one distribution for the month of December 2003, paid on January 15, 2004 for US$0.10 per
    unit4)Both cash flow from operations and earnings
    from operations are non-GAAP measures. It is managements view that this information
    is relevant for investors in order to compare 2003, 2002 and 2001 without the impact of
    one-time non-recurring events. Both cash flow from operations and earnings from operations
    are reconciled to GAAP earnings in the earnings and cash flow sections of the management
    discussion and analysis.






PRODUCTION INCOME

Production income increased by 180% in 2003 from $25.7 million to $72.1
million. Approximately 30% of this increase was due to the higher commodity prices in
effect during 2003 and 70% was due to the higher production volumes in 2003.

Production income increased by 55% in Q4, 2003 from $10.1 million to
$15.6 million. All of this increase is due to higher production, as pricing actually
decreased slightly in Q4, 2003 by 4%.

Enterra drilled 47 wells in 2003, including 20 wells at Clair and 19
wells at Sylvan Lake. The two projects represented almost 60% of Enterras 2003
capital expenditures. The 2003 drilling program resulted in 31 oil wells (31.0 net) and 3
gas wells (1.1 net) for an 86% success rate. Enterras production in 2003 averaged
5,024 boe/day, consisting of 3,862 bbls/day of oil and 6,972 mcf/day of natural gas, for a
mix of 77% oil and 23% natural gas.

Enterras production in Q4 of 2003 averaged 5,206 boe/day,
consisting of 4,110 bbls/day of oil and 6,572 mcf/day of natural gas, for a mix of 79% oil
and 21% natural gas. Enterras production in Q4 of 2002 averaged 3,221 boe/day,
consisting of 2,142 bbls/day of oil and 6,477 mcf/day of natural gas, for a mix of 67% oil
and 33% natural gas. Enterra drilled 15 wells in Q4, 2003 compared to 54 wells in Q4,
2002.

Enterra exited 2003 at a rate of 6,460 boe/day, consisting of 4,890
bbls/day of oil and 9,420 mcf/day of natural gas, for a mix of 76% oil and 24% natural
gas.  This represents a 21% increase over the 2002 exit rate of 5,335 boe/day.

Production income (in
    Thousands except for volumes and pricing)Q4
    2003
    Q4
    2002
    Change
    Year
    2003
    Year
    2002
    ChangeCrude oil and natural gas liquids
    $12,022
    $6,878
    + 75%
    $ 55,185
    $ 18,075
    + 205%Natural gas
    3,576
    3,182
    + 12%
    16,912
    7,671
    + 120%Total production income
    $15,598
    $10,060
    + 55%
    $ 72,097
    $ 25,746
    + 180%VolumesAverage oil production (in bbls/day)
    4,110
    2,142
    + 92%
    3,862
    1,460
    + 164%Average gas production (in mcf/day)
    6,572
    6,477
    + 1%
    6,972
    5,157
    + 35%Average total production (in boe/day)
    5,206
    3,221
    + 62%
    5,024
    2,320
    + 117%Exit oil production (in bbls/day)
    4,890
    4,205
    + 16%
    4,890
    4,205
    + 16%Exit gas production (in mcf/day)
    9,420
    6,780
    + 39%
    9,420
    6,780
    + 39%Exit total production (in boe/day)
    6,460
    5,335
    + 21%
    6,460
    5,335
    + 21%Commodity Pricing BenchmarksWest Texas Intermediate (US$/bbl)
    31.18
    28.29
    + 10%
    31.10
    26.13
    + 19%Exchange rate (US$)
    0.7600
    0.6372
    + 19%
    0.7164
    0.6371
    + 12%Edmonton Par ($/bbl)
    39.85
    43.18
    - 8%
    43.39
    40.20
    + 8%NYMEX (US$/mmbtu)
    5.44
    4.33
    + 26%
    5.49
    3.36
    + 63%Alberta Spot ($/mcf)
    5.69
    5.52
    + 3%
    6.50
    3.96
    + 64%Commodity Prices received by EnterraAverage price received per bbl of oil
    31.78
    34.93
    - 9%
    39.12
    33.86
    + 16%Average
    price received per mcf of natural gas
    5.91
    5.34
    + 11%
    6.65
    4.08
    + 63%






Production expenses increased by 112% in 2003 and by 27% in Q4 compared to their
respective periods in 2002. These increases are consistent with the higher production
levels in 2003. Both as a percentage of revenue and on a per boe basis, Enterra reduced
its operating costs in 2003, mainly due to operating efficiencies gained at Clair in the
fourth quarter of 2003 by implementing a sales line which eliminated trucking and terminal
fees for that area. This is why the production expenses per boe were 21% lower in Q4, 2003
compared to 2002 ($6.19 per boe in 2003 compared to $7.88 per boe in 2002)

Production expenses (in Thousands
    except for percentages and per boe amounts)Q4
    2003
    Q4
    2002
    Change
    
    Year
    2003
    Year
    2002
    ChangeProduction expenses
    $ 2,966
    $ 2,335
    + 27%
    
    $ 12,762
    $ 6,018
    + 112%As a percentage of production revenue
    19%
    23%
    - 17%
    
    18%
    23%
    - 22%Production
    expenses per boe
    $ 6.19
    $ 7.88
    - 21%
    
    $ 6.96
    $ 7.11
    - 2%






Royalties, which include Crown, freehold and overriding royalties,
increased by 320% in 2003 and by 128% in Q4 compared to their respective periods in 2002.
These increases are the result of both the increased production in 2003 and the higher
commodity prices in effect during the year. Most royalties are calculated on a sliding
scale based on commodity prices. As commodity prices increase, so do the royalty rates.
Conversely, the Alberta Royalty Tax Credit is reduced as commodity prices increase. Since
royalties are not calculated by reference to any hedging position entered into by Enterra,
any hedging loss will result in a higher royalty expense as a percentage of production
revenue. These factors were the reason for the increase (50% for the year and 47% for Q4)
in royalty expense both as a percentage of production revenue and on a per boe basis.

Royalties (in Thousands except for
    percentages and per boe amounts)Q4
    2003
    Q4
    2002
    Change
    
    Year
    2003
    Year
    2002
    ChangeRoyalties
    $ 3,916
    $ 1,721
    + 128%
    
    $ 17,656
    $ 4,203
    + 320%As a percentage of production revenue
    25%
    17%
    + 47%
    
    24%
    16%
    + 50%Royalties
    per boe
    $ 8.18
    $ 5.81
    + 41%
    
    $ 9.63
    $ 4.96
    + 94%






General and administrative expenses increased by 84% in 2003 and 50% in
Q4 compared to their respective periods in 2002. Approximately 80% of the increase in 2003
is the result of additional staffing requirements. Other areas which incurred higher
expenses were marketing and travel costs, insurance premiums, and higher regulatory
compliance costs both for the Canadian and U.S. exchanges. Capitalized general and
administrative costs were consistent in both years, $1,787,000 (or 32% of total general
and administrative expenses) in 2003 and $1,450,900 (or 39% of total general and
administrative expenses) in 2002. The non-cash portion of general and administrative
expenses in 2003 relate to the value assigned to 200,000 warrants (see Note 9(h) of the
Financial Statements for details).

General and administrative expenses (in
    Thousands except for percentages and per boe amounts)Q4
    2003
    Q4
    2002
    Change
    
    Year
    2003
    Year
    2002
    ChangeGeneral and administrative expenses 
    cash portion
    $ 760
    $ 505
    + 50%
    
    $ 3,103
    $ 1,683
    + 84%General and administrative expenses 
    non-cash portion
    -
    -
    
    
    $ 281
    -As a percentage of production revenue (cash
    portion)
    5%
    5%
    0%
    
    4%
    7%
    - 43%General and
    administrative expenses per boe (cash portion)
    $ 1.59
    $ 1.71
    - 7%
    
    $ 1.69
    $ 1.99
    - 15%






Interest expense increased by 42% in 2003 and decreased by 23% in Q4
compared to their respective periods in 2002. The 2003 increase is due to the higher
average outstanding loan balances during the year. The decrease in Q4 is due to the fact
that, on average, the Q4 loan balances were higher in 2002 because of the higher drilling
activity in Q4, 2002 compared to Q4, 2003 (54 wells were drilled in Q4, 2002 compared to
15 wells drilled in Q4, 2003).



- 35 -

Interest expense (in
    Thousands except for percentages and per boe amounts)Q4
    2003
    Q4
    2002
    Change
    
    Year
    2003
    Year
    2002
    ChangeLong-term debt, including bank
    debt at end of period
    $ 38,128
    $ 29,358
    + 30%
    
    $ 38,128
    $ 29,358
    + 30%Interest expense
    $ 410
    $ 531
    - 23%
    
    $ 1,749
    $ 1,236
    + 42%As a percentage of production
    revenue
    3%
    5%
    - 40%
    
    2%
    5%
    - 60%Interest
    expense per boe
    $ 1.79
    $ 0.86
    - 52%
    
    $ 0.95
    $ 1.46
    - 35%






Depletion and depreciation expense increased by 152% in 2003 and by 80%
in Q4 compared to their respective periods in 2002. The increase is due to a higher
production rate in the year and Q4, 2003. The depletable base was consistent in both years
as the capital expenditures, net of proceeds on disposal of properties, were $33 million
in 2003 and $ 30 million in 2002.

Depletion and depreciation (in
    Thousands except for percentages and per boe amounts)Q4
    2003
    Q4
    2002
    Change
    
    Year
    2003
    Year
    2002
    ChangeDepletion and depreciation expense
    $ 6,236
    $ 3,468
    + 80%
    
    $ 23,447
    $ 9,306
    + 152%As a percentage of production revenue
    40%
    34%
    + 18%
    
    33%
    36%
    - 8%Depletion
    and depreciation expense per boe
    $ 13.02
    $ 11.70
    + 11%
    
    $ 12.79
    $ 10.99
    + 16%






The combined federal and provincial income taxes decreased in 2003 to
40.75% from 42.12% in 2002. The actual tax provision recorded on the financial statements
is at much lower rates in both 2003 and 2002 (29.32% in 2003 and 17.32% in 2002). The rate
was very low in 2002 mainly because of the $3.1 million gain on redemption of preferred
shares which was not a taxable gain for tax purposes, resulting in a lower tax provision
in that year. The rate was also lower in 2003 mainly due to changes in the timing
differences related to the Crown royalties and the resource allowance calculation, and to
differences related to the Trust distributions, which are deductible in part for tax
purposes but are not deducted to arrive at net earnings.

Income and capital taxes (in Thousands except for percentages)

Year
    2003
    Year
    2002
    ChangeIncome tax expense
    
    $ 2,075
    $ 1,043
    + 99%Combined federal and provincial income tax
    rate
    
    40.75%
    42.12%
    - 3%Actual tax rate as a percentage of net
    earnings
    
    29.32%
    17.32%
    + 71%Estimated tax pools at December 31Canadian oil and gas property expense (COGPE)
    
    $ 11,268
    $ 20,148Canadian exploration expense (CEE)
    
    $ 8,832
    $ 9,870Canadian development expense (CDE)
    
    $ 21,297
    $ 4,708Undepreciated capital cost (UCC)
    
    $ 23,247
    $ 27,109Other
    
    $ 1,740
    $ 2,331$ 66,384
    $ 64,166
    + 3%






Both earnings from operations and net earnings are presented below in
order to show the impact of one-time events which occurred in both years. Earnings were
higher in 2002 because of the impact of a $3.1 million gain on redemption of preferred
shares. The opposite occurred in 2003 as earnings were reduced by the re-organization
costs related to the conversion to a trust structure in the fourth quarter of 2003.

- 36 -

Enterras earnings from operations increased by 341% in 2003 and
decreased by 8% in Q4 compared to their respective periods in 2002. The large 2003
increase was caused by increased production (up 117% for the year), higher prices (higher
on average by 29% during 2003) and, except for royalties, lower expenses as a percentage
of revenue in 2003. The results were similar on a per unit basis, $0.68 per unit in 2003
compared to $0.16 per unit in 2002, for with a 326% increase.

Q4s earnings from operations were almost identical in each year,
despite the higher production in 2003. This is due mainly to lower royalties and lower
depletion in 2002. The large loss in Q4 of 2003 is the direct results of the $5.8 million
in costs related to the trust conversion.

As mentioned earlier, it is managements view that earnings from
operations is a good measure of performance and an appropriate benchmark when comparing
results from year to year or quarter to quarter because it excludes one-time non-recurring
events which may otherwise distort the financial results. Earnings from operations is a
non-GAAP measure, reconciled with GAAP net earnings in the table below:

Earnings (in Thousands
    except for per unit/share amounts)Q4
    2003
    Q4
    2002
    Change
    Year
    2003
    Year
    2002
    ChangeEarnings from operations
    $ 1,020
    $ 1,108
    - 8%
    $ 12,835
    $ 2,909
    + 341%Deduct re-organization costs
    (5,756)
    -
    
    (5,756)
    -Add back gain on redemption of preferred
    shares
    -
    -
    
    -
    3,111Earnings (loss) before income taxes
    $(4,736)
    $ 1,108
    N/A
    $ 7,079
    $ 6,020
    + 18%Deduct income taxes
    (367)
    (393)
    
    (2,075)
    (1,043)Net earnings (loss)
    $(5,103)
    $ 715
    N/A
    $ 5,004
    $ 4,977
    + 1%Earnings from operations as a percentage of
    revenue
    7%
    11%
    - 36%
    18%
    11%
    + 64%Earnings from operations on a per boe basis
    $ 2.13
    $ 3.74
    - 43%
    $ 7.00
    $ 3.44
    + 103%Per unit/share informationEarnings from operations per unit/share
    $ 0.05
    $ 0.06
    - 17%
    $ 0.68
    $ 0.16
    + 326%Net earnings (loss) per unit/share
    $ ( 0.25)
    $ 0.04
    N/A
    $ 0.26
    $ 0.27
    0%Average
    number of units/share outstanding
    20,205
    18,336
    + 10%
    18,954
    18,309
    + 4%




- 37 -



Cash flow from operations grew by 205% in 2003 and by 54% in Q4
compared to their respective periods in 2002. As a percentage of revenue, cash flow from
operations was consistent in both years and both quarters, at 51% of revenue in 2003
compared to 46% in 2002, and 48% of revenue in Q4 of both 2003 and 2002.

Higher production volumes and higher commodity prices in 2003 are the main factors
behind the increase. Pricing was not a factor in Q4 because prices actually showed a small
decrease of 4% in 2003 compared to 2002.

The changes on a per unit basis showed similar results: an increase of 195% in 2003
compared to 2002 and 40% in Q4, 2003 compared to Q4, 2002.

As mentioned earlier, it is managements view that cash flow from
operations is a very useful measure of performance, especially in light of Enterras
conversion to an oil and gas income trust. Cash flow from operations is the key factor in
setting the monthly distribution rate. As discussed in the earnings section above, cash
flow from operations is also a good benchmark when comparing results from year to year or
quarter to quarter because it excludes one-time non-recurring events which may otherwise
distort the financial results. Cash flow from operations is a non-GAAP measure, reconciled
with GAAP net earnings in the table below:

Cash flow from operations (in
    Thousands except for per unit/share amounts)Q4
    2003
    Q4
    2002
    Change
    Year
    2003
    Year
    2002
    ChangeNet earnings (loss)
    $ (5,103)
    $ 715
    N/A
    $ 5,004
    $ 4,977
    + 1%Add back re-organization costs
    5,756
    -
    
    5,756
    -Deduct gain on redemption of preferred shares
    -
    -
    
    -
    (3,111)Add back depletion and depreciation
    6,236
    3,468
    
    23,447
    9,306Add back (deduct) amortization of deferred
    financing charges
    (27)
    391
    
    262
    391Add back future income taxes
    323
    360
    
    1,941
    911Deduct amortization of deferred gain
    -
    (83)
    
    (237)
    (524)Add back non-cash expense related to value of
    warrants
    282
    -
    
    282
    -Cash flow from operations
    $ 7,467
    $ 4,851
    + 54%
    $ 36,455
    $ 11,950
    + 205%Cash flow from operations as a percentage of
    revenue
    48%
    48%
    0%
    51%
    46%
    + 11%Cash flow from operations on a per boe basis
    $ 15.59
    $ 16.37
    - 5%
    $ 19.88
    $ 14.11
    + 41%Per unit informationCash flow from operations per unit/share
    $ 0.37
    $ 0.26
    + 40%
    $ 1.92
    $ 0.65
    + 195%Average
    number of units/shares outstanding
    20,205
    18,336
    + 10%
    18,954
    18,309
    + 4%






Capital expenditures, net of disposals, for the year ended December 31,
2003 were $33.3 million (2002 - $30.1 million) and $11.9 million for Q4 (2002 - $20.1
million). Enterra drilled 47 wells in 2003, resulting in 31 oil wells (31.0 net) and 3 gas
wells (1.1 net) for an 86% success rate. Enterra drilled 62 wells (57.7 net) in 2002,
resulting in 25 oil wells (23.7 net) and 37 gas wells (34.0 net). There were 15 wells
drilled in Q4 of 2003 compared with 54 wells drilled in Q4 of 2002, which is why the
capital expenditures in Q4, 2002 are twice as high as Q4, 2003. Proceeds on disposal of
oil and gas properties were $18.3 million in 2003 (2002 - $5.8 million). These proceeds
used to reduce debt and replenish working capital relate almost exclusively to the sale of
the Grand Forks properties, which occurred in the second quarter of 2002 and which
accounted for $5.3 million of the total proceeds.

Capital expenditures (in
    Thousands except for percentages and per boe amounts)Q4
    2003
    Q4
    2002
    Change
    
    Year
    2003
    Year
    2002
    ChangeProperty acquisitions
    $ 73
    $ 89
    
    
    $ 8,539
    $ 4,829Proceeds on disposal of properties
    (2,228)
    (410)
    
    
    (18,263)
    (5,810)Drilling (exploration and development)
    10,048
    14,386
    
    
    28,390
    21,519Facilities and equipment
    4,008
    6,027
    
    
    14,368
    9,347Other
    92
    8
    
    
    286
    235$ 11,993
    $ 20,100
    - 40%
    
    $ 33,320
    $ 30,120
    + 11%




Enterra paid distributions of US$0.10 per unit for the month of
December 2003 and for the first two months of 2004. The distribution for the month of
March 2004 was raised to US$0.11 per unit. Cash distributions are paid on the 15th
of the following month (e.g. the March distribution would be paid on April 15).

Enterra's distributions are highly dependent on commodity prices,
primarily the price of crude oil. Enterra mitigates this risk by hedging some of its oil
production. A detailed schedule of Enterras hedging history and current position is
included in the next section dealing with liquidity and capital resources.

For Canadian tax purposes 72.37% of the December distribution is
taxable income to unitholders for the 2003 tax year. The remaining 27.63%  is a tax
deferred return of capital which will reduce the unitholder's cost base of the unit for
purposes of calculating a capital gain or loss upon ultimate disposition of the trust
units.

- 38 -

For U.S. tax purposes, the December distribution is a 2004 taxable
event. Enterras distributions are typically dividend income for U.S. unitholders,
without any portion deemed a return of capital.

OUTLOOK 2004

Enterras focus in 2004 continues to be on enhancing value for its
unitholders by delivering a stable and growing monthly distribution, combined with a
potential for a price appreciation of its trust units in the market place.
Our objectives for 2004 include:

- accretive reserve replacement through property acquisitions with
    development upside.
- a growing distribution from quarter to quarter.
- controlling and reducing operating costs.
- maintaining an effective development program through farm-out and
    joint venture arrangements.
- keeping our investors up-to-date with our plans through  timely
    communications. a focus on per unit growth.

LIQUIDITY AND CAPITAL RESOURCES

Enterras bank debt at December 31, 2003 was $34 million (2002 -
$24.4 million). In both periods the funds were used to acquire capital assets and support
ongoing operations. At December 31, 2003 Enterras bank facility consisted of a line
of credit of $39.6 million (2002 - $26.7 million). Interest on amounts drawn is based on
the banks prime rate plus 0.25%. Enterra was in full compliance with all of its bank
covenants at December 31, 2003

> 

In both 2003 and 2002 Enterra financed its ongoing operations in part
by selling properties. Proceeds from such sales were $18.3 million in 2003 and $5.8
million in 2002. As a trust, Enterra is less likely to dispose of properties unless the
funds from such sales can be re-invested in acquiring new properties with development
upside potential as part of Enterras reserve replacement strategy.

Enterras preferred shares were redeemed in 2002 for $2.3 million,
paid for with cash of $1.75 million and a note of $550,000. The note was subsequently
settled for $325,000, resulting in a gain of $206,181 net of related legal costs.

In 2002 Enterra closed a sale-leaseback arrangement on some of its
production and processing equipment for $5 million. The funds were used for the
Companys 2002 drilling program. The lease agreement calls for 60 monthly payments of
$88,802, with an option to purchase of $1 million on the last day of the 60th
month. This arrangement is accounted for as a capital lease. At December 31, 2003 the
balance outstanding on all capital leases was $4,168,548 (2002 - $4,921,598).

On January 16, 2004 Enterra entered into a financing agreement whereby
Enterra will issue 1,650,000 Trust Units at a price of US$10.00 per unit for gross
proceeds of US$ 16,500,000. Payment will be received pending registration of the units.

These funds will be applied towards the East Central Alberta property
acquisition described below.

On January 30, 2004 the Trust closed an acquisition of properties in
East Central Alberta for $19,847,000.

On February 20, 2004 the Trust completed a private placement of
1,049,400 Trust Units at a price of US$11.25 per unit for gross proceeds of US$11,805,750
(US$10,265,463 net of financing costs). These funds will be used for drilling projects
which Enterra began prior to its conversion to a trust.

Capital expenditures should be approximately $5-10 million in 2004
because Enterra, as an income trust, will be distributing approximately 80% of its cash
flow through its monthly distributions. Enterras strategy for growth in 2004 will be
focused on property acquisition which will be funded with a combination of additional debt
and equity.

Enterra has approximately $66 million in tax pools available at
December 31, 2003. (2002 - $64 million)

Enterra had several costless collars and forward contracts in place
during the year in order to minimize the volatility in crude oil pricing. Below is a
summary of Enterras hedging operations in 2002 and 2003:





Hedging
    summaryDescription
    Quantity
    Pricing
    Gain (loss) on contractOil contract Oct. 1/2000 to Sept 30/2003 (sold
    in January 2001)
    350/650 bbls of oil/day
    US$24.15 to US$27.19
    $1,680,000Zero collar from November 1/2001 to April
    30/2002
    500 bbls of oil/day
    Floor US$20  Ceiling
    US$24
    ($41,878)Zero collar from October 1/2002 to March
    31/2003
    500 bbls of oil/day
    Floor US$22  Ceiling
    US$28
    ($65,440)Natural gas contract from Nov 1/2002 to March
    31/2003
    1,500 mcf of gas/day
    C$4.60 per mcf
    ($486,225)Natural gas contract from Nov 1/2002 to March
    31/2003
    1,500 mcf of gas/day
    C$4.45 per mcf
    ($520,200)Oil contracts from April 1/2003 to December
    31/2003
    2,000 bbls of oil/day
    From US$29.50 to US$29.80
    ($246,937)**Contracts entered into
    subsequent to December 31/2003:**Oil contracts from January 1/2003 to June
    30/2004
    500 bbls of oil/day
    US$26.75 per barrelOil contracts from January 1/2003 to June
    30/2004
    500 bbls of oil/day
    US$26.68 per barrelOil contracts from January 1/2003 to June
    30/2004
    1,000 bbls of oil/day
    C$38.50 per barrelOil
    contracts from July 1/2004 to December 31/2004
    500 bbls of oil/day
    C$40.50 per barrel


As a trust, Enterra will distribute approximately 80% of its available cash flow to its
unitholders. Future growth will be financed with a combination of additional trust units
and bank debt. Enterra's level of distribution will fluctuate depending on future
commodity prices and operating results. The portion of cash not distributed   
will be used for maintenance capital or to reduce bank debt.  Management believes it
has sufficient capital at year-end to meet its current requirements.

SENSITIVITIES

We are exposed to all of the normal risks inherent within the oil and gas sector,
including commodity price risk, foreign-currency rate risk, interest rate risk and credit
risk. We manage our operations in a manner intended to minimize our exposure, as described
in notes 12 and 13 to the consolidated financial statements.

Credit Risk

Credit risk is the risk of loss resulting from non-performance of
contractual obligations by a customer or joint venture partner. A substantial portion of
our accounts receivable are with customers in the energy industry and are subject to
normal industry credit risk. We assess the financial strength of our customers and joint
venture partners through regular credit reviews in order to minimize the risk of
non-payment.

Foreign Exchange Risk

We are exposed to market risk from changes in the exchange rate between
U.S. and Canadian dollars. The price we receive for oil and natural gas production is
based on a benchmark expressed in U.S. dollars, which is the standard for the oil and
natural gas industry worldwide. Our monthly distributions are also based on a value
expressed in U.S. dollars. However, we pay our operating expenses, drilling expenses and
general overhead expenses in Canadian dollars. Changes to the exchange rate between U.S.
and Canadian dollars can adversely affect us. When the value of the U.S. dollar increases,
we receive higher revenue and when the value of the U.S. dollar declines, we receive lower
revenue on the same amount of production sold at the same prices. A change of $0.01 in the
U.S. to CDN dollar would impact Enterras earnings by approximately $193,000 and its
cash flow by $394,000.







Our financial condition, results of operations and capital resources
are highly dependent upon the prevailing market prices of oil and natural gas. These
commodity prices are subject to wide fluctuations and market uncertainties due to a
variety of factors that are beyond our control. Factors influencing oil and natural gas
prices include the level of global demand for crude oil, the foreign supply of oil and
natural gas, the establishment of and compliance with production quotas by oil exporting
countries, weather conditions which determine the demand for natural gas, the price and
availability of alternative fuels and overall economic conditions. It is impossible to
predict future oil and natural gas prices with any degree of certainty. Sustained weakness
in oil and natural gas prices may adversely affect our financial condition and results of
operations, and may also reduce the amount of oil and natural gas reserves that we can
produce economically. Any reduction in our oil and natural gas reserves, including
reductions due to price fluctuations, can have an adverse affect on our ability to obtain
capital for our development activities. Similarly, any improvements in oil and natural gas
prices can have a favorable impact on our financial condition, results of operations and
capital resources. If the WTI oil price were to change by US$1.00 per bbl, the impact on
Enterras earnings would be approximately $869,000 and the impact on Enterras
cash flow would be approximately $1,774,000. If natural gas prices were to change by
US$0.50 per mcf, the impact on Enterras earnings would be approximately $873,000 and
the impact on Enterras cash flow would be approximately $1,781,000.

We periodically use hedges with respect to a portion of our oil and
natural gas production to mitigate our exposure to price changes. While the use of these
derivative arrangements limits the downside risk of price declines, such use may also
limit any benefits which may be derived from price increases.

Interest Rate Risk

Interest rate risk exists principally with respect to our indebtedness
that bears interest at floating rates. At December 31, 2003, we had $34 million of
indebtedness bearing interest at floating rates. If interest rate were to change by one
full percentage point, the net impact on Enterras earnings would be approximately
$244,000 and the net impact on Enterras cash flow would be approximately $337,000.

Summarized below are Enterras sensitivities to various risks, based on its 2003
operations:

Sensitivities
    Estimated
    2004 impact on:Net Income
    Cash FlowCrude oil  US$1.00/bbl change in WTI
    $869,000
    $1,774,000Natural Gas  US$0.50/mcf change
    $873,000
    $1,781,000Foreign Exchange - $0.01 change in U.S. to CDN
    dollar
    $193,000
    $394,000Interest
    rate  1% change
    $244,000
    $337,000




RELATED PARTY TRANSACTIONS

There were no related party transactions in 2003 or 2002

OFF BALANCE SHEET ARRANGEMENTS

There were no off balance sheet arrangements in 2003 or 2002.

COMMITMENTS

Enterra has only two ongoing commitments over the next five years, one
related to the capital lease and the other related to the rental payments for our office
space. The rental payments were $299,132 in 2003 (2002 - $240,255 and 2001 - $167,545).
These commitments are outlined below:



Thereafter2004
    2005
    2006
    2007
    2008Minimum capital lease
    payments
    $786,889
    $809,538
    $877,697
    $1,702,342Rental payments re-office
    space
    460,447
    467,717
    414,770
    309,990
    640,920$1,247,336
    $1,277,255
    $1,292,467
    $2,012,332
    $640,920


Note: The above table does not include any imputed interest, as
presented in note 14 of the 2003 financial statements.



- 41 -

NEW ACCOUNTING PRONOUNCEMENTS





In December 2002, the CICA approved Section 3110 Asset Retirement
Obligations to harmonize Canadian GAAP with Financial Accounting Standards Board Statement
No. 143. The section replaces previous guidance on future removal and site restoration
costs and is effective for fiscal years beginning on or after January 1, 2004. The asset
retirement obligation liability is initially measured at fair value, which is the
discounted future value of the liability. The fair value is capitalized as part of the
related asset and is depleted over the useful life of the asset. The liability accretes
until the obligation is settled. Prior periods will be restated in accordance with the new
standard. We have estimated the December 31, 2003 asset retirement obligation to be $2.2
million, based on a total future liability of $4.2 million.

The CICA issued Accounting Guideline 16, which replaces Accounting
Guideline 5, Full Cost Accounting in the Oil and Gas Industry. The guideline is effective
for fiscal years beginning on or after January 1, 2004 and is to be accounted for on a
prospective basis. The most significant change is the modification of the ceiling test to
be consistent with CICA Section 3063, Impairment of Long-lived Assets. The new guideline
limits the carrying value of oil and gas properties to their fair value. There is no write
down of our property, plant and equipment under either the old or the new method as of
December 31, 2003.

Effective March 31, 2004, the Trust and all reporting issuers in Canada
will be subject to new disclosure requirements as per National Instrument 51-102
"Continuous Disclosure Obligations". This new instrument proposes shorter
reporting periods for filing of annual and interim financial statements, MD&A and
Annual Information Form (AIF). The instrument also requires enhanced disclosure in the
annual and interim financial statements, MD&A and AIF. Under this new instrument, it
will no longer be mandatory for the Trust to mail annual and interim financial statements
and MD&A to unitholders, but rather these documents will be provided on an "as
requested" basis. The Trust continues to assess the implications of this new
instrument which will be implemented in 2004.

Other accounting standards issued by the CICA during the year ended December 31, 2003 are
not expected to materially impact us.





> 

(a) Interpretation No. 46, "Consolidation of
    Variable Interest Entities", effective for the Trust for the period ending December
    31, 2004.

(b) FAS No. 150, "Accounting for Certain Financial Instruments
    with Characteristics of both Liabilities and Equity", effective for financial
    statements issued after June 15, 2003.

(c) FAS No. 132 (revised 2003), "Employers Disclosures about
    Pensions and Other Post Retirements Benefits - an amendment of SFAS No. 87, 88 and
    106", effective for financial statements issued after December 15, 2003.

(d) FAS No. 149, "Amendment of Statement 133 on Derivative
    Instruments and Hedging Activities", effective for contracts entered into or modified
    after June 30, 2003.

The Trust will continue to assess the applicability of these standards in the future.



- 42 -

RESULT OF OPERATIONS 2002 COMPARED TO 2001

OVERVIEW

Enterra achieved record revenue, cash flow and earnings in 2002. Enterras growth
occurred primarily in the fourth quarter of the year when revenue and cash flow doubled
from the previous quarter. Enterra exited the year with a production rate of 5,335
boe/day, doubling the previous quarter exit rate of 2,456 boe/day. Enterra continued to
reduce operating costs during 2002, resulting in an average cost per boe of $7.11 compared
to $8.38 in 2001. Total reserves increased by 36% to 11.08 million boe with the majority
of the increase coming from the Clair property. Enterra also strengthened its balance
sheet by redeeming a substantial portion of its preferred shares for a gain of $3.1
million.

Summarized financial and operational data (in
    Thousands except for volumes and per share amounts)Year 2002
    Year 2001
    ChangeExit production rate (boe per day)
    5,335
    2,675
    + 99%Average annual production revenue
    $ 25,746
    $ 20,264
    + 27%Average annual production volumes (boe per
    day)
    2,320
    1,906
    + 22%Cash flow from operations for the year
    $ 11,950
    $ 9,810
    + 22%Cash flow per share for the year
    $ 1.31
    $ 1.40
    - 7%Earnings (including $3.1 million gain on
    redemption of preferred shares in 2002)
    $ 4,977
    $ 1,617
    + 208%Earnings per share for the year
    $ 0.54
    $ 0.23
    + 134%Average number of shares outstanding during
    year
    9,154,491
    6,992,393
    + 31%Average price per bbl of oil during year
    $ 33.86
    $ 30.53
    + 11%Average price per mcf of natural gas during
    year
    $ 4.08
    $ 3.66
    + 11%Operating costs per boe during year
    $ 7.11
    $ 8.38
    - 15%General and
    administrative expenses per boe during year
    $ 1.99
    $ 0.81
    + 145%




PRODUCTION INCOME

Production income increased by 27% in 2002 from $20.3 million to $25.7 million, mainly
due to the accelerated drilling program in effect during the fourth quarter of the year.
Enterra drilled only eight wells in the first nine months of 2002 but drilled 54 wells in
the fourth quarter alone. Commodity prices were slightly higher, on average, in 2002 than
2001 a 40% decrease.

Enterra drilled 62 wells (57.7 net) in 2002, resulting in 25 oil
wells (23.7 net) and 37 gas wells (34.0 net) for a success ratio of 100%. Enterras
production in 2002 averaged 2,320 boe/day, consisting of 1,460 bbls/day of oil and 5,157
mcf/day of natural gas, for a mix of 63% oil and 37% natural gas.

Enterra exited 2002 at a rate of 5,335 boe/day, consisting of
4,205 bbls/day of oil and 6,780 mcf/day of natural gas, for a mix of 79% oil and 21%
natural gas. This represents a 99% increase over the 2001 exit rate of 2,675 boe/day.



- 43 -



Production income (in
    Thousands except for volumes and pricing)Year 2002
    Year 2001
    ChangeCrude oil and natural gas liquids
    $ 18,075
    $ 17,773
    + 2%Natural gas
    7,671
    2,491
    + 208%Total production income
    $ 25,746
    $ 20,264
    + 27%VolumesAverage oil production during year (in
    bbls/day)
    1,460
    1,595
    - 8%Average gas production during year (in
    mcf/day)
    5,157
    1,863
    + 177%Average total production during year (in
    boe/day)
    2,320
    1,906
    + 22%Exit oil production (in bbls/day)
    4,205
    2,065
    + 104%Exit gas production (in mcf/day)
    6,780
    3,660
    + 85%Exit total production (in boe/day)
    5,335
    2,675
    + 99%PricingAverage price received per bbl of oil during
    year
    $ 33.86
    $ 30.53
    + 11%Average
    price received per mcf of natural gas during year
    $ 4.08
    $ 3.66
    + 11%




PRODUCTION EXPENSES

Production expenses increased by 3% from $5.8 million in 2001 to $6 million in 2002. On
a per boe basis, Enterra reduced its operating costs by 15% from $8.38 per boe in 2001 to
$7.11 per boe in 2002. This trend should continue in 2003 as Enterra focuses its efforts
on selected core areas.

Production expenses (in Thousands
    except for percentages and per boe amounts)Year 2002
    Year 2001
    ChangeProduction expenses
    $ 6,018
    $ 5,830
    + 3%As a percentage of production revenue
    23%
    29%
    - 21%Production
    expenses per boe
    $ 7.11
    $ 8.38
    - 15%


ROYALTIES

Royalties, which include Crown, freehold and overriding royalties, increased by 32% as
a result of both the increased production in 2002 and the higher commodity prices in
effect during the year.

Royalties (in Thousands except for
    percentages and per boe amounts)Year 2002
    Year 2001
    ChangeRoyalties, net of Alberta Royalty Tax Credit
    $ 4,203
    $ 3,182
    + 32%As a percentage of production revenue
    16%
    16%
    -Royalties
    per boe
    $ 4.96
    $ 4.58
    + 8%




GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses increased by 198% in 2002 as a result of additional
staffing requirements and higher marketing and travel costs, in addition to higher
compliance costs as a result of trading on both a Canadian and U.S. exchange. Overhead
recovery costs, which are a recovery of overhead costs related to capital expenditures,
were also lower in 2002 as Enterras average working interest was over 90% in 2002,
compared to 53% in 2001.



- 44 -

General and administrative expenses (in
    Thousands except for percentages and per boe amounts)Year 2002
    Year 2001
    ChangeGeneral and administrative expenses
    $ 1,683
    $ 565
    + 198%As a percentage of production revenue
    6%
    3%
    + 100%General and
    administrative expenses per boe
    $ 1.99
    $ 0.81
    + 145%






INTEREST EXPENSE

Interest expense increased in 2002 by 110% due to the higher average outstanding loan
balances during the year, especially in the fourth quarter.

Interest expense (in Thousands
    except for percentages and per boe amounts)Year 2002
    Year 2001
    ChangeLong-term debt, including bank debt at
    year-end
    $ 29,358
    $ 18,409
    + 59%Interest expense
    $ 1,236
    $ 589
    + 110%As a percentage of production revenue
    5%
    3%
    + 67%Interest
    expense per boe
    $ 1.46
    $ 0.85
    + 72%




DEPLETION AND DEPRECIATION

Depletion and depreciation expense increased by 35% in 2002 to $9.3 million from $6.9
million in 2001. The increase is due to both a higher 2002 production rate and a higher
2002 depletable base as a result of spending in excess of $35 million in capital
expenditures during the year.

Depletion and depreciation (in
    Thousands except for percentages and per boe amounts)Year 2002
    Year 2001
    ChangeDepletion and depreciation expense
    $ 9,306
    $ 6,870
    + 35%As a percentage of production revenue
    36%
    34%
    + 6%Depletion
    and depreciation expense per boe
    $ 10.99
    $ 9.88
    + 11%




INCOME AND CAPITAL TAXES

Income taxes decreased by 60% in 2001 as a result of the reduced earnings. Current
income taxes were substantially reduced as a result of the Big Horn acquisition, which
provided the basis for a more effective tax structure within the Enterra group.



Income and capital taxes (in
    Thousands except for percentages and per boe amounts)Year 2002
    Year 2001
    ChangeIncome tax expense
    $ 1,043
    $ 682
    + 53%As a percentage of production revenue
    4%
    3%
    + 33%Income tax expense per boe
    $ 1.23
    $ 0.98
    + 26%Estimated tax poolsCanadian oil and gas property expense (COGPE)
    $ 20,148
    $ 16,832Canadian exploration expense (CEE)
    9,870
    1,606Canadian development expense (CDE)
    4,708
    6,250Undepreciated capital cost (UCC)
    27,109
    18,464Other
    2,331
    2,152$ 64,166
    $ 45,304
    + 42%




- 45 -

EARNINGS

Enterras earnings for the year ended December 31, 2002 were $4.98
million (2001 - $1.62 million). This large increase was caused mainly by a $3.1 million
gain on redemption of preferred shares which occurred in the first quarter of 2002.
Enterra redeemed 6,123,870 of its Series 1 preferred shares with a face redemption price
of $5,205,290 for $2.1 million, resulting in a gain of $3.1 million. Without this gain,
earnings would have been $1.86 million, an increase of 15%. Earnings per share for the
year ended December 31, 2002 were $0.54 (2001 - $0.23). The weighted average number of
shares outstanding in 2002 was 9,154,491 (2001  6,992,393).

Earnings (in Thousands
    except for number of shares and per share amounts)Year 2002
    Year 2001
    ChangeEarnings from operations
    $ 2,909
    $ 3,228
    - 10%Add gain on redemption of preferred shares
    3,111
    -Less restructuring charges
    -
    (929)Less income taxes
    (1,043)
    (682)Net earnings
    $ 4,977
    $ 1,617
    + 208%Net earnings per share
    $ 0.54
    $ 0.23
    + 134%Average
    number of shares outstanding during year
    9,154,491
    6,992,393
    + 31%


CASH FLOW

Cash flow from operations grew by 22% in 2002 to $11.95 million compared to $9.81
million in 2001. Cash flow per share in 2002 was $1.31 per share, a 7% decrease from 2001
when it was $1.40.

Cash flow (in
    Thousands except for number of shares and per share amounts)Year 2002
    Year 2001
    ChangeNet earnings
    $ 4,977
    $ 1,617
    + 208%Add back depletion and
    depreciation
    9,306
    6,870Add back amortization of deferred
    financing charges
    391
    -Add back future income taxes
    911
    562Add back deferred gain
    -
    1,680Deduct amortization of deferred
    gain
    (524)
    (919)Less gain on redemption of
    preferred shares
    (3,111)
    -Cash
    flow from operations
    $ 11,950
    $ 9,810
    + 22%Cash flow per
    share
    $ 1.31
    $ 1.40
    - 6%Average
    number of shares outstanding during year
    9,154,491
    6,992,393
    + 31%


CAPITAL EXPENDITURES

Capital expenditures for the year ended December 31, 2002 were $35.88
million (2001 - $14.96 million). Drilling activity was minimal in the first ten months of
2002 but increased substantially in November and December. Almost $20 million was spent in
the fourth quarter of 2002, representing over 50% of the entire 2002 capital expenditures.
Enterra drilled 62 (57.7 net) wells in 2002, resulting in 25 (23.7 net) oil wells and 37
(34.0 net) gas wells. Only 8 wells were drilled in the first nine months of 2002. The
remaining 54 wells (87% of total wells drilled in 2002) were all drilled in the fourth
quarter of 2002. Proceeds on disposal of oil and gas properties were $5.8 million in 2002
(2001 - $1.7 million). These proceeds relate almost exclusively to the sale of the Grand
Forks properties, which occurred in the second quarter of 2002 and which accounted for
$5.3 million of the total proceeds. Finding costs, on a proved plus 1/2 probable basis,
improved by 17% in 2002 to $7.72 compared to $9.30 in 2001.



- 46 -

ITEM 6. Directors, Senior Management and Employees

New Enterra's officers, directors and executive officers as of December
31, 2003 were:

Name
    Age
    PositionLuc Chartrand
    47
    Chief Executive Officer, President
    and DirectorLynn Wiebe
    46
    Chief Financial OfficerReginald J. Greenslade
    40
    ChairmanH.S. (Scobey) Hartley
    71
    DirectorNorman G.
    Wallace
    65
    DirectorWilliam E.
    Sliney
    65
    Director (Mr. Sliney became a
    director on March 19, 2004)


Luc Chartrand. Mr. Chartrand worked for KPMG as a Chartered
Accountant from 1985 to 1988 when he became a tax manager in their Calgary office. He left
shortly thereafter and worked as a consultant to several Calgary companies. He moved to
Toronto in 1990 to assist in the relocation and takeover of Financial Trust by Central
Capital. He remained in Toronto until 1992 when he returned to Calgary with Morgan
Financial Corporation. Shortly thereafter, he joined Bonus Resource Services Corp. as its
Chief Financial Officer. Mr. Chartrand joined Big Horn Resources Ltd. in the fall of 1994
and became Chief Financial Officer in 1996. He became Chief Financial Officer of Enterra
in August 2001 and Chief Executive Officer, President and director of Enterra Energy Trust
in November 2003.

Lynn Wiebe. Ms Wiebe joined Enterra
on October 1, 2003 as Chief Financial Officer. Ms. Wiebe is a Chartered Accountant and
held various progressive positions at KPMG LLP from 1980 to 1986. From 1986 to 1995, Ms.
Wiebe was employed by Gulf Canada Resources in supervisory positions in Financial
Reporting, Corporate Reporting, Oil Marketing and Accounting and various other areas
within the company. From 1995 to May 2001 Ms. Wiebe left the permanent workforce to pursue
other interests. During the period from May 2001 to October 2002, she provided financial
services to a number of organizations, including Trans Canada Pipelines and a private
mortgage company, through contracting and consulting engagements. In May of 2003, Ms.
Wiebe was employed by Control-F1 Corporation, an eSupport software company, as their Chief
Financial Officer, until she joined Enterra in October, 2003.

Reginald (Reg) J. Greenslade. Mr. Greenslade was President, CEO
and Director of Enterra Energy Corp from the fall of 2001 until November 2003 and
continues as Chairman of Enterra Energy Trust. Enterra Energy Corp. was formed by the
combination of Big Horn Resources Ltd. and Westlinks Resources Ltd in the fall of 2001. He
is also the Chairman, Chief Executive Officer and director of JED Oil Inc. He was a
director of PASW Inc., a software development company, from February 2001 to July 2001.
From 1995 until the formation of Enterra, Mr. Greenslade was the President, CEO and
Director of Big Horn Resources Ltd. Prior to his position with Big Horn, Mr. Greenslade
was with CS Resources Limited in the areas of exploitation engineering and project
management from 1993 to 1995. Prior to 1993, Mr. Greenslade was employed by Saskatchewan
Oil and Gas Corporation in the capacities of project management, production, and reservoir
engineering. He has extensive experience with secondary recovery schemes and is recognized
for his work in the specialized field of horizontal well technology. All the above
companies were publicly traded in either the U.S., Canada, or both, during the periods
indicated.

H.S. (Scobey) Hartley. Mr. Hartley
has a Bachelor of Science degree in Geology from Texas Tech University. Mr. Hartley has
been a director of Enterra since May, 2000. Mr. Hartley was the President of Prism
Petroleum Ltd. and a predecessor company from December, 1990 through December, 1996. Mr.
Hartley has been the Chairman of Prism Petroleum Ltd. since January, 1997. Mr. Hartley has
served as the President of Faster Oilfield Services since June, 1995, and was the
President of Cayenne Energy Corp. from 1990 to 1996. Mr. Hartley was the President and a
Director of Scaffold Connection Corporation from February, 2000 to November, 2001. Mr.
Hartley has been a Director of Cathedral Energy Services Ltd. since June, 2001.

Norman G. Wallace. Mr. Wallace has
been a director of Enterra since May, 2000. Mr. Wallace resigned as a director of Enterra
in August, 2001 and was reappointed in June, 2002. He has been the owner of Wallace
Construction Specialties Ltd. since 1972. Mr. Wallace received a Bachelor of Commerce
degree from the University of Saskatchewan in 1968.



William E. Sliney. Mr. Sliney became a director on March 19,
2004. He has been the president of PASW, Inc. since August 2001 and was chairman from
October 2000 to August 2001. Previously Mr. Sliney was the chief financial officer for
Legacy Software Inc. from 1995 to 1998. From 1993 to 1994, Mr. Sliney was chief executive
officer for Gumps. Mr. Sliney received his masters in business administration from the
University of California at Los Angeles.



- 47 -

Board of Directors

New Enterra is authorized to have a board of at least three directors
and no more than ten. New Enterra currently has five directors. Directors are elected for
a term of about one year, from annual meeting to annual meeting, or until an earlier
resignation, death or removal. Each officer serves at the discretion of the board or until
an earlier resignation or death.  There are no family relationships among any of New
Enterra's directors or officers.  Alberta securities laws requires that New Enterra
have at least two independent outside directors who are not officers or employees of
Enterra.

Currently directors of New Enterra receive an annual retainer of $
10,000. Directors are also entitled to be compensated for their out-of-pocket costs,
including travel and accommodation, relating to their attendance at any directors'
meeting. Finally, the directors of New Enterra are entitled to participate in our trust
unit option plan. During the year ended December 31, 2003, there were no options granted
to the current directors (not including options granted to a director who is also a named
executive officer). Except as described herein, no compensation by way of annual retainer
or meeting fees was paid to directors for acting in such capacity in the year ended
December 31, 2003.

Committees of the Board of Directors

New Enterra's Board of Directors currently has an audit committee, a
compensation committee, a corporate governance committee and a reserves committee.

Audit Committee. New Enterra's audit committee consists of Mr.
Sliney (Chairman), Mr. Hartley and Mr. Wallace, all three being independent directors. The
audit committee reviews in detail and recommends approval of the full board of our annual
and quarterly financial statements; recommends approval of the remuneration of our
auditors to the full board; reviews the scope of the audit procedures and the final audit
report with the auditors, and reviews our overall accounting practices and procedures and
internal controls with the auditors.

Compensation Committee. New Enterra's compensation committee
consists of Mr. Hartley (Chairman), Mr. Wallace and Mr. Greenslade. The compensation
committee recommends approval to the full board of the compensation of the Chief Executive
Officer, the annual compensation budget for all other employees, bonuses, grants of stock
options and any changes to our benefit plans.

Corporate Governance Committee. New Enterra's corporate
governance committee consists of Mr. Wallace (Chairman), Mr. Greenslade and Mr. Hartley.
The corporate governance committee determines the scope and frequency of periodic reports
to the board concerning issues relating to overall financial reporting, disclosure and
other communications with all stakeholders.

Reserves Committee. New Enterra's reserves committee consists
of Mr. Wallace (Chairman) and Mr. Hartley. The reserves committee reviews and recommends
approval to the full board of Enterras annual reserve report as prepared by
independent reservoir engineers.

- 48 -

Executive Compensation

The following table provides a summary of compensation earned during
the last fiscal year ended December 31, 2003 by our executive officers during 2003.

All monetary amounts are in Canadian dollars.

**Name and**
    **Principal Position**
    **Year**
    **Annual
    Compensation**
    **Long-Term Compensation**
    **All Other Compensation
    ($)****Awards**
    **Payouts****Salary
    ($)**
    **Bonus
    ($)**
    **Other Annual Compensation($)**
    **Securities Under Options/ SARs Granted
    (#)**
    **Restricted Shares or Restricted Share Units
    ($)**
    **LTIP
    Payouts
    ($)**Luc Chartrand (1)President and Chief Executive Officer
    2003
    2002
    2001
    182,495
    158,355
    133,365
    298,180Lynn WiebeChief Financial Officer
    2003
    2002
    2001
    28,200
    6,000
    
    5,000


(1) Mr. Chartrand was Chief Financial Officer in 2001, 2002 and for most of
2003. He became Chief Executive Officer of New Enterra on November26, 2003

(2)

Management Contracts

We have no employment contracts with any employees.

Trust Units Options

We grant trust unit options from time to time to directors, officers,
key employees, and consultants. The terms and conditions of the options, in accordance
with resolutions of our board of directors and the policies of the Toronto Stock Exchange,
will not exceed a term of five years. The option price may be at a discount to market
price, which discount will not, in any event, exceed that permitted by any stock exchange
on which our shares are listed for trading.

Ten percent of our of issued and outstanding trust units from time to
time are reserved for issuance pursuant to trust unit options. The aggregate number of
trust units reserved for issuance under option grants, together with any other employee
trust unit option plans, options for services and employee trust unit purchase plans, will
not exceed ten percent of our issued and outstanding trust units. In addition, the
aggregate number of trust units so reserved for issuance to any one person shall not
exceed five percent of the issued and outstanding trust units.

If an optionee ceases to be eligible due to the loss of corporate
office or employment for any reason other than death, the option terminates not later than
30 days after the loss of such corporate office; provided that in the event of termination
of employment for cause, the board of directors may resolve that the option shall
terminate on the date of such termination. Option agreements also provide that estates of
deceased participants can exercise their options for a period not exceeding one year
following death.

Trust Unit Options Granted During the Most Recently Completed Financial Year

There were no trust unit options granted during the fiscal year ended
December 31, 2003.



- 49 -

Option Grants During Fiscal Year Ended December 31, 2003

Individual Grants
    Potential Realizable Value at Assumed Annual Rate of
    Stock Price Appreciation for Option Term (1)Number ofShares of Common Stock
    **Percentage of Total** OptionsGranted to Employees inYear EndingDec. 31, 2003
    **Exercise**Price Per Share
    **Expiration**
    Date
    5%
    10%Lynn Wiebe
    5,000
    15.87 %
    $18.58
    Sep 30/08
    $25,667
    $56,716(1)Assumed
      annual appreciation rates are established by regulations and are not a forecast of future
      appreciation. The amounts shown are pre-tax and assume the options will be held throughout
      the entire five-year term. If trust units do not increase in value after the grant date of
      the options, the options are valueless.




Aggregated Option Exercises During the Most Recently Completed Financial Year and
Financial Year End Option Values

The following table sets forth the aggregate of options exercised by
our executive officers during the year ended December 31, 2003 and the December 31, 2003
year-end values for options granted to the executive officers. All monetary amounts are in
Canadian dollars.  These options relate to Old Enterra shares, prior to the trust
conversion.

Name
    Securities Exercised (#)
    Aggregate Value Realized ($)
    Unexercised Options at FY-End Exercisable/ Unexercisable
    (#)
    Value of Unexercised in-the-Money Options at FY-End
    Exercisable/ Unexercisable ($)(1)Luc Chartrand
    72,500
    $1,153,230
    Nil
    Nil/NilLynn Wiebe
    5,000
    $ 20,100
    Nil
    Nil/Nil


> (1) The closing price of our trust units on the Toronto Stock Exchange
>   on the last trading day in December, 2003 was $ 14.51.



- 50 -



ITEM 7.     Major Shareholders and Related Party Transactions

A.    Major Shareholders

PRINCIPAL STOCKHOLDERS

The following table sets forth information regarding beneficial
ownership of our trust units as of December 31, 2003, by:

>  each person who is known by us to beneficially own more than 5% of our outstanding
>   trust units;
>    each of our executive officers and directors; and
>    all executive officers and
>     directors as a group.

Trust units not outstanding but deemed beneficially owned because an
individual has the right to acquire the trust units within 60 days are treated as
outstanding when determining the amount and percentage of trust units owned by that
individual and by all directors and executive officers as a group.

Number of
    trust units
    Beneficially
    Owned
    Percentage
    of shares
    outstandingLuc Chartrand (1)
    45,450
    0.24%Lynn Wiebe(1)
    5,000
    0.02%Reginald J. Greenslade (1)
    195,147
    1.03%H.S. (Scobey) Hartley (1)
    84,400
    0.45%Norman G. Wallace(1)
    70,000
    0.37%William E. Sliney(1)(2)
    -All
    directors and executive officers as a group (five persons)
    399,997
    2.11%


__________

Notes:

(1)    The address of each officer and director is Suite
2600, 500 - 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V6.

(2)     Mr. Sliney did not become a director or
Enterra until March 19, 2004.



B.    Related Party Transactions

There were no related party transactions in 2003 or 2002

C.     Interests of Experts and Counsel

Not Applicable



ITEM 8. Financial Information

A. Consolidated Financial Statements and Other Financial Information

Pages F-1 to F-14.

B. Significant Changes

None.



- 51 -

ITEM 9. The Offer and Listing

A.      Offer and Listing details

Not Applicable, except for Item 9A (4).

**Price Range of Common Stock and Trading Markets**

On November 28, 2003 the buisness of Old Enterra was reorganized as an
income trust. In conjunction with this reorganization holders of Enterra Energy Corp.
common stock received two trust units for each share of common stock held or
non-registered exchangeable shares convertible into an equal number of trust units. All
historical information before November 28, 2003 in the following tables has been restated
to reflect this exchange.

Old Enterra's shares commenced trading on the TSX Venture Exchange
("TSXV") under the symbol "WLX" during the quarter ended September 30,
1998. Our shares traded on the National Quotation Bureau's pink sheets ("Pink
Sheets") under the symbol "WLKSF" from April 26, 2000 to January 10, 2001
when the shares commenced trading on the Nasdaq SmallCap Market under the symbol
"EENC" and under the symbol "ENT" on the TSX Venture Exchange
("TSX"). On May 21, 2003 the shares commenced trading on the Nasdaq National
Market under the symbol "EENC." On June 20, 2003 the shares commenced trading on
the Toronto Stock Exchange under the symbol "ENT". Following our reorganization
as an income trust in November 2003 our trust units commenced trading on the Nasdaq
National Market and Toronto Stock Exchange under the same symbols as the common stock
which was retired as a result of the reorganization.

The following table sets forth the bid prices, in Canadian or U.S.
dollars, as reported by the TSXV, TSX and NASDAQ National and SmallCap Markets/pink
sheets, for the periods shown, as restated for periods prior to November 28, 2003 to
reflect the 2:1 conversion from common shares to trust units.

Toronto Stock Exchange/TSX Venture Exchange
    (Cdn. $s)
    Nasdaq SmallCap Market/Pink Sheets
    (U.S. $s)
    Nasdaq National Market
    (U.S. $s)Five most recent full fiscal years:
    High
    Low
    High
    Low
    High
    LowYear ended December 31, 2003
    14.10
    4.995
    7.75
    3.245
    10.91
    4.625Year ended December 31, 2002
    5.75
    1.30
    3.75
    0.735
    n/a
    n/aYear ended December 31, 2001
    3.75
    1.15
    2.405
    0.825
    n/a
    n/aYear ended December 31, 2000
    3.90
    2.225
    2.305
    1.705
    n/a
    n/aYear ended December 31, 1999
    0.525
    0.205
    n/a
    n/a
    n/a
    n/aYear ended December 31, 2003:Quarter ended December 31, 2003
    14.10
    5.775
    n/a
    n/a
    10.91
    4.625Quarter ended September 30, 2003
    12.935
    8.54
    n/a
    n/a
    9.625
    6.00Quarter ended June 30, 2003
    10.25
    8.925
    7.75
    4.045
    n/a
    n/aQuarter ended March 31, 2003
    7.00
    4.995
    4.75
    3.245
    n/a
    n/aYear ended December 31, 2002:Quarter ended December 31, 2002
    5.75
    3.00
    3.75
    1.90
    n/a
    n/aQuarter ended September 30, 2002
    3.225
    2.30
    2.095
    1.475
    n/a
    n/aQuarter ended June 30, 2002
    2.745
    2.135
    1.74
    1.125
    n/a
    n/aQuarter ended March 31, 2002
    2.48
    1.30
    1.165
    0.735
    n/a
    n/aYear ended December 31, 2001:Quarter ended December 31, 2001
    1.875
    1.15
    1.195
    0.825
    n/a
    n/aQuarter ended September 30, 2001
    2.50
    1.375
    1.70
    0.875
    n/a
    n/aQuarter ended June 30, 2001
    3.225
    2.35
    2.125
    1.39
    n/a
    n/aQuarter ended March 31, 2001
    3.75
    2.5
    2.405
    1.61
    n/a
    n/aSix most recent months ended:October 2003
    13.01
    9.25
    n/a
    n/a
    9.95
    6.755November 2003
    14.10
    6.25
    n/a
    n/a
    10.91
    4.75December 2003
    7.54
    5.775
    n/a
    n/a
    5.815
    4.625January 2004
    8.625
    6.505
    n/a
    n/a
    6.295
    5.05February 2004
    8.90
    7.87
    n/a
    n/a
    6.70
    5.825March 2004
    9.40
    8.955
    n/a
    n/a
    7.195
    6.70




- 52 -

B.     Plan of Distribution

Not Applicable

C.    Markets

See Item 9.A

D. Selling Shareholders

Not Applicable

E. Dilution

Not Applicable

ITEM 10. ADDITIONAL INFORMATION

A. Share Capital

DESCRIPTION OF SECURITIES

Trust Units

An unlimited number of trust units may be created and issued pursuant
to our trust indenture. Each trust unit entitles the holder thereof to one vote at any
meeting of the unitholders and represents an equal fractional undivided beneficial
interest in any distribution from us, including net income, net realized capital gains or
other amounts, and in our net assets in the event of termination or winding up of our
business. All trust units rank among themselves equally and ratably without
discrimination, preference or priority. Each trust unit is transferable, is not subject to
any conversion or pre-emptive rights and entitles the holder thereof to require us to
redeem any or all of the trust units held by such holder.

Exchangeable Shares

In conjunction with our reorganization we issued exchangeable shares
that are intended to be the economic equivalent of trust units. We issued a total of
2,000,000 exchangeable shares.

The exchangeable shares are convertible at any time into trust units at
the option of the holder based on an exchange ratio. The exchange ratio is increased
monthly based on the cash distribution paid on the trust units divided by the ten day
weighted average unit price preceding the distribution payment date. From November 25 to
December 31, 2003, a total of 4,404 exchangeable shares were converted into 4,404 trust
units at the exchange ratio 1:1 prevailing at the time. Cash distributions are not paid on
the exchangeable shares. On the third anniversary of the issuance of the exchangeable
shares, subject to our extension , or at our option when the aggregate number of issued
and outstanding exchangeable shares is less than 1,000,000, the exchangeable shares will
be redeemed for trust units based upon the value of that number of trust units equal to
the exchange ratio on the redemption date. The exchangeable shares are not listed for
trading on an exchange.

Holders of exchangeable shares can require us to redeem their shares at
any time and carry special voting rights. The special voting rights equal the number of
trust units into which the exchangeable shares are then exchangeable multiplied by the
number of votes to which the holder of one trust unit is then entitled.

Ownership Restrictions

There is no law or government decree or regulation in Canada that
restricts the export or import of capital, or affects the remittance of dividends,
interest or other payments to non-resident holders of trust units, other than withholding
tax requirements.

There is no limitation imposed by Canadian law or by our charter or
other charter documents on the right of a non-resident to hold or vote our trust units,
other than as provided by the Investment Canada Act, the North American Free Trade
Agreement Implementation Act (Canada) and the World Trade Organization Agreement
Implementation Act. The Investment Canada Act requires notification and, in certain cases,
advance review and approval by the Government of Canada of the acquisition by a
"non-Canadian" of "control" of a "Canadian business," each
as defined in the Investment Canada Act. In general, the threshold for review will be
higher in monetary terms for a member of the World Trade Organization or North American
Free Trade Agreement.

Transfer Agent and Registrar

The transfer agent and registrar for our trust units is Olympia Trust
Company at its principal offices in Calgary and Toronto, Canada.



- 53 -

TRUST UNITS ELIGIBLE FOR FUTURE SALE

Future sales of substantial amounts of our trust units in the public
market, in either Canada or the United States, or even the perception that such sales
could occur, could adversely affect the market price for our trust units and could impair
our future ability to raise capital through an offering of our equity securities.

We have outstanding 18,951,556 trust units, assuming no exercise of
outstanding warrants and options. All these units are freely tradable, without
restrictions imposed by applicable securities laws.

We intend to register the trust units issuable pursuant to our trust
unit option plan. At December 31, 2003 there were no options outstanding to purchase trust
units, all of which would be eligible for immediate resale in Canada, and in the United
States by persons who are not affiliates of Enterra.

Our affiliates may reoffer and resell trust units in Canada, in
accordance with the foregoing, provided that such trust units are offered and sold by them
pursuant to Rule 903 of Regulation S under the Securities Act and that at the time the
Toronto Stock Exchange continues to be the principal market for our trust units.

B.    Trust Indenture / Memorandum and Articles of Association



Enterra Energy Trust is an open ended unincorporated investment trust
governed by the laws of the Province of Alberta and created pursuant to the Trust
Indenture.

The principal undertaking of the Trust is to issue trust units and to
acquire and hold debt instruments, royalties and other interests. The direct and indirect
wholly owned subsidiaries of the Trust carry on the business of acquiring and holding
interests in petroleum and natural gas properties and assets related thereto.

The Trustee is prohibited from acquiring any investment which (a) would
result in the cost amount to the Trust of all "foreign property" (as defined in
the Income Tax Act (Canada)) which is held by the Trust to exceed the amount
prescribed by section 5000 of the regulations to the Income Tax Act (Canada) or (b)
would result in the Trust not being considered either a "unit trust" or a
"mutual fund trust" for purposes of the Income Tax Act (Canada).

Enterra is authorized to issue an unlimited number of trust units. See
"Item 10 A Share Capital." The trust unitholders have no rights to share in
Enterras profits, are subject to no redemption or sinking fund provisions, have no
liability for further capital calls and are not subject to any discrimination due to
number of trust units owned.

By not more than 50 days or less than seven days in advance of a
distribution, the board may establish a record date for the determination of the persons
entitled to such dividend. Any distribution unclaimed after a period of six years from the
record date shall be forfeited and revert to Enterra.

The rights of trust unitholders can be changed at any time in a
unitholders meeting where the modifications are approved by 66 2/3% of the unitholders
represented by proxy or in person at the meeting.

All unitholders are entitled to vote at annual or special meetings of
unitholders, provided that they were unitholders as of the record date. The record date
for unitholders meetings may precede the meeting date by no more than 50 days and not less
than 21 days, providing that notice by way of advertisement is given to unitholders at
least seven days before such record date. Notice of the time and place of meetings of
unitholders may not be less than 21 or greater than 50 days prior to the date of the
meeting.



New Enterra is amalgamated under the laws of the Province of Alberta,
Canada (corporation number 207913385). The Articles of Amalgamation and by-laws provide no
restrictions as to the nature of the business operations of New Enterra.



- 54 -

The governing legislation requires a director to inform New Enterra, at
a meeting of the Board of Directors, of any interest in a material contract or proposed
material contract with New Enterra. No director may vote in respect of any such contract
made by them with New Enterra or in any such contract in which they are interested, and
such director shall not be counted for purposes of determining a quorum. However, these
provisions do not apply to (i) an arrangement by way of security for money lent to or
obligations undertaken by them: (ii) a contract relating primarily to their remuneration
as a director, officer, employee or agent of New Enterra or an affiliate: (iii) a contract
for indemnity or insurance of the director as allowed under the governing legislation: or
(iv) a contract with an affiliate.

The Board of Directors may exercise all powers of New Enterra to borrow
or raise money, and to give guarantees, and to mortgage or charge its properties and
assets, and to issue debentures, debenture stock and other securities, outright or as
security for any debt, liability or obligation of New Enterra or any third party.

There are no age limit requirements regarding retirement of directors
and there is no minimum share ownership required for a directors election to the
board.

All directors of New Enterra are elected at each annual meeting of
unitholders of the Trust and cumulative voting is not permitted.

C. Material Contracts

None

D. Exchange Controls

There is no law or government decree or regulation in Canada that
restricts the export or import of capital, or affects the remittance of dividends,
interest or other payments to non-resident holders of trust units, other than withholding
tax requirements.

There is no limitation imposed by Canadian law or by our acharter or
our charter documents on the right of a non-resident to hold or vote sour trust units,
other than as provided by the "Investment Canada Act", the "North American
Free Trade Agreement Implementation Act (Canada)" and the "World Trade
Organization Agreement Implementation Act."

The Investment Canada Act requires notification and, in certain cases,
advance review and approval by the Government of Canada of the acquisition by a
"non-Canadian" of "control" of a "Canadian business", each
as defined in the Investment Canada Act. In general, the threshold for review will be
higher in monetary terms for a member of the World Trade Organization or North American
Free Trade Agreement.

E. Taxation



The following is a summary of the material Canadian federal income
tax considerations under the Income Tax Act (Canada) (the "Tax Act") in
respect of the acquisition of trust units pursuant this offering generally applicable to
purchasers who (i) hold trust units as capital property for purposes of the Tax Act, and
(ii) at all material times deal at arm's length, and are not affiliated, with Enterra and
New Enterra for purposes of the Tax Act. Generally, trust units will be considered to be
capital property to a holder who does not hold such securities in the course of carrying
on a business and has not acquired them in one or more transactions considered to be an
adventure in the nature of trade. Certain Canadian resident unitholders who might not
otherwise be considered to hold their trust units as capital property may, in certain
circumstances, be entitled to make an irrevocable election in accordance with subsection
39(4) of the Tax Act to have such trust units treated as capital property.

This summary is not applicable to either a unitholder that is a
"financial institution" or a "specified financial institution", as
defined for purposes of the Tax Act, or a unitholder, an interest in which would be a
"tax shelter investment" under the Tax Act.

This summary is based upon the provisions of the Tax Act and the
regulations thereunder ("Tax Regulations") in force as of the date hereof, all
specific proposals to amend the Tax Act and the Tax Regulations that have been publicly
announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof
(the "Proposed Amendments") and Canadian counsel's understanding of the current
published administrative and assessing policies of the Canada Customs and Revenue Agency
(the "CCRA").



- 55 -

This summary is not exhaustive of all
possible Canadian federal income tax considerations applicable to the acquisition of trust
units and, except for the Proposed Amendments, does not take into account or anticipate
any changes in the law, whether by legislative, governmental or judicial action or changes
in the administrative and assessing practices of the CCRA. This summary does not take into
account any provincial, territorial or foreign tax considerations, which may differ
significantly from those discussed herein.

This summary is of a general nature only and is not intended to be
relied on as legal or tax advice or representations to any particular investor.
Consequently, potential investors are urged to seek independent tax advice in respect of
the consequences to them of the acquisition of trust units having regard to their
particular circumstances.

Residents of Canada

This portion of the summary is applicable to a unitholder who, for the
purposes of the Tax Act and at all relevant times, is resident, or deemed to be resident,
in Canada.

Status of the Trust

Based upon a certificate from New Enterra, the Trust qualifies as a
mutual fund trust under the provisions of the Tax Act and the balance of the summary
assumes that the Trust will continue to so qualify. [Enterra has also advised Canadian
counsel that it intends to apply to the CCRA for the Trust to be registered as a
"registered investment" under the Tax Act from inception, and this summary
further assumes that the Trust will be so registered.]

The requirements to qualify as a mutual fund trust for purposes of the
Tax Act include:

> 1. the sole undertaking of the Trust must be the investing of its funds
>     in property (other than real property or interests in real property), the acquiring,
>     holding, maintaining, improving, leasing or managing of any real property (or an interest
>     in real property) that is capital property of the Trust, or any combination of these
>     activities;
>     2. the Trust must comply on a continuous basis with certain
>     requirements relating to the qualification of the trust units for distribution to the
>     public, the number of unitholders and the dispersal of ownership of trust units. In this
>     regard, there must be at least 150 unitholders, each of whom owns not less than one
>     "block" of trust units having a fair market value of not less than $500. A
>     "block" of trust units means 100 trust units if the fair market value of one
>     trust unit is less than $25; and
>     3. continuously from the time of its creation, all or substantially all
>     of the Trust's property must consist of property other than property that would be
>     "taxable Canadian property" for purposes of the Tax Act.

The Trust has certain restrictions on its
activities and its powers and certain restrictions on the holding of taxable Canadian
property, such that it is reasonable to expect that the requirements will be satisfied.
However, Canadian counsel can provide no assurances that the requirements will continue to
be met.

If the Trust were not to so qualify as a mutual fund trust or were not
to be registered as a registered investment from inception, the income tax considerations
would in some respects be materially different from those described below.

Taxation of the Trust

The Trust is subject to tax in each taxation year on its income or loss
for the year, computed as though it were a separate individual resident in Canada. The
taxation year of the Trust will end on December 31 of each year.

The Trust will be required to include in its income for each taxation
year (i) all interest on the Series A Notes that accrues to, becomes receivable or is
received by it before the end of the year, except to the extent that such interest was
included in computing its income for a preceding year (ii) all interest on the CT Note
that accrues to, becomes receivable or is received by it before the end of the year,
except to the extent that such interest was included in computing its income for a
preceding year (iii) the net income of Commercial Trust paid or payable to the Trust in
the year and (iv) all amounts in respect of any oil and gas royalties, if any, held by the
Trust including any amounts required to be reimbursed to the grantor of the royalty in
respect of Crown charges.

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In computing its income, the Trust will
generally be entitled to deduct reasonable administrative expenses incurred to earn
income. The Trust will be entitled to deduct the costs incurred by it in connection with
the issuance of trust units on a five-year, straight-line basis (subject to pro-ration for
short taxation years). The Trust may also deduct amounts which become payable by it to
unitholders in the year, to the extent that the Trust has net income for the year after
the inclusions and deductions outlined above and to the extent permitted under the Tax
Act. An amount will be considered to have become payable to a unitholder in a taxation
year only if it is paid in that year by the Trust or the unitholder is entitled in that
year to enforce payment of the amount. Under the Trust Indenture, net income of the Trust
for each year will be paid or made payable by way of cash distributions to the
unitholders. The Trust Indenture also contemplates other situations in which the Trust may
not have sufficient cash to distribute all of its net income by way of such cash
distributions. In such circumstances, such net income will be payable to unitholders in
the form of the issuance by the Trust of additional trust units ("Reinvested trust
units"). Accordingly, it is anticipated that the Trust will generally not have any
taxable income for the purposes of the Tax Act.

Under the Trust Indenture, income received by the Trust may be used to
finance cash redemptions of trust units. A redemption of trust units that is effected by a
distribution by the Trust to a unitholder of Series A Notes will be treated as a
disposition by the Trust of such Series A Notes for proceeds of disposition equal to the
fair market value thereof and may give rise to a taxable capital gain to the Trust.

The Trust will be entitled for each taxation year to reduce (or receive
a refund in respect of) its liability, if any, for tax on its net taxable capital gains by
an amount determined under the Tax Act based on the redemption or retraction of trust
units during the year (the "Capital Gains Refund"). In certain circumstances,
the Capital Gains Refund for a particular taxation year may not completely offset the
Trust's tax liability on net realized capital gains for such taxation year.

For purposes of the Tax Act, the Trust generally intends to deduct, in
computing its income and taxable income, the full amount available for deduction in each
year. As a result of such deductions and the Trust's entitlement to a Capital Gains
Refund, it is expected that the Trust will not be liable for any material amount of tax
under the Tax Act. However, no assurance can be given in this regard.

[The Trust will apply to be a "registered investment" under
the Tax Act from the Trust's inception. It may be eligible to be registered if it is a
mutual fund trust, and it may have its registration revoked by the CCRA if it ceases to be
a mutual fund trust and did not otherwise qualify for registered investment status.
Assuming that the Trust becomes a registered investment, the Trust may be subject to a
special tax under Part XI of the Tax Act if it acquires or holds foreign property in
excess of the limits provided in the Tax Act or enters into certain agreements to acquire
shares of a corporation at a price that may differ from the fair market value of the
shares at the time of acquisition. Based on Enterra's certificate as to certain factual
matters and the terms of the Trust Indenture, which restrict its investments in foreign
property, the Trust will not become liable for such tax.]

If the Trust ceases to qualify as a mutual fund trust, the Trust may be
required to pay tax under Part XII.2 of the Tax Act. The payment of Part XII.2 tax by the
Trust may have material adverse tax consequences for certain unitholders.

Taxation of unitholders

> Income from trust units

The income of a unitholder from the trust units will be considered to
be income from property for the purposes of the Tax Act. Any deduction or loss of the
Trust for the purposes of the Tax Act cannot be allocated to and treated as a deduction or
loss of a unitholder.

A unitholder will generally be required to include in computing income
for a particular taxation year of the unitholder the portion of the net income of the
Trust for a taxation year, including taxable dividends and net taxable capital gains, that
is paid or becomes payable to the unitholder in that particular taxation year, whether
such amount is payable in cash or in Reinvested trust units. Provided that appropriate
designations are made by Commercial Trust and the Trust, such portion of the Trust's net
taxable capital gains and taxable dividends, if any, as are paid or payable to a
unitholder will effectively retain their character as taxable capital gains and taxable
dividends, respectively, and will be treated as such in the hands of the unitholder for
purposes of the Tax Act.

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The amount of any net taxable capital gains
designated by the Trust to a unitholder will be included in the unitholder's income under
the Tax Act for the year of disposition as a taxable capital gain. See "Taxation
of Capital Gains and Capital Losses" above. The non-taxable portion of net
realized capital gains of the Trust that is paid or becomes payable to a unitholder in a
year will not be included in computing the unitholder's income for the year. Any other
amount in excess of the net income of the Trust that is paid or becomes payable by the
Trust to a unitholder in a year will generally not be included in the unitholder's income
for the year. However, a unitholder is required to reduce the adjusted cost base of the
trust units held by such unitholder by each amount payable to the unitholder otherwise
than as proceeds of disposition of trust units (except to the extent that the amount
either was included in the income of the unitholder or was the unitholder's share of the
non-taxable portion of the net capital gains of the Trust, the taxable portion of which
was designated by the Trust in respect of the unitholder). To the extent that the adjusted
cost base of a trust unit is less than zero, the negative amount will be deemed to be a
capital gain of a unitholder from the disposition of the trust unit in the year in which
the negative amount arises. See "Taxation of Capital Gains and Capital Losses"
below.

The amount of dividends designated by the Trust to a unitholder will be
subject to, among other things, the gross-up and dividend tax credit provisions for
unitholders who are individuals, the refundable tax under Part IV of the Tax Act
applicable to "private corporations" and "subject corporations" (as
defined under the Tax Act), and the deduction in computing taxable income in respect of
dividends received by taxable Canadian corporations. In general, net income of the Trust
that is designated as taxable dividends from taxable Canadian corporations or as net
taxable capital gains may increase an individual unitholder's liability for alternative
minimum tax.

> Cost of trust units

The cost to a unitholder of a trust unit will generally include all
amounts paid by the unitholderfor the trust unit. Reinvested trust units issued to a
unitholder as a non-cash distribution of income will have a cost equal to the amount of
income distributed by the issuance of such Reinvested trust units. This cost will be
averaged with the adjusted cost base of all other trust units held by the unitholder as
capital property in order to determine the respective adjusted cost base of each trust
unit.

> Disposition of trust units

Upon the disposition or deemed disposition by
a unitholder of a trust unit, whether on a redemption or otherwise, the unitholder will
generally realize a capital gain (or a capital loss) equal to the amount by which the
proceeds of disposition exceed (or are less than) the aggregate of (i) such unitholder's
adjusted cost base of the trust units disposed of, determined immediately before the
disposition and (ii) any reasonable costs of disposition. A redemption of trust units in
consideration for cash distributed to the unitholder in satisfaction of the Market
Redemption Price, or the issuance of a Redemption Note by the Trust in satisfaction of the
Market Redemption Price, will be a disposition of such trust units for proceeds of
disposition equal to the cash or the principal amount of the Redemption Note, as the case
may be. Where trust units are redeemed by the distribution of Series A Notes to the
unitholder, the proceeds of disposition to the unitholder of such trust units will
generally be equal to the fair market value of the Series A Notes so distributed less any
capital gain or income realized by the Trust in connection with such redemption which has
been designated by the Trust to the redeeming unitholder.

Where a unitholder that is a corporation or a trust (other than a
mutual fund trust) disposes of a trust unit, the unitholder's capital loss from the
disposition will generally be reduced by the amount of dividends from taxable Canadian
corporations previously designated by the Trust to the unitholder, except to the extent
that a loss on a previous disposition of a trust unit has been reduced by such dividends.
Similar rules apply where a corporation or trust (other than a mutual fund trust) is a
member of a partnership that disposes of trust units. See "Taxation of Capital
Gains and Capital Losses" below.

The cost to a unitholder of any Series A Notes distributed to the
unitholder by the Trust on a redemption of trust units will be equal to the fair market
value of such Series A Notes at the time of distribution, excluding any accrued interest
thereon. Such a unitholder will be required to include in income interest on such Series A
Notes (including interest that had accrued to the date of distribution of the Series A
Notes to the unitholder) in accordance with the provisions of the Tax Act. To the extent
that the unitholder is required to include in income any interest that had accrued to the
date of distribution of the Series A Notes, an offsetting deduction will be available in
computing the unitholder's income from the Trust.

A unitholder will be required to include in income interest on the
Redemption Notes in accordance with the provisions of the Tax Act.

A unitholder that is corporation that is throughout a relevant taxation
year a "Canadian-controlled private corporation", as defined in the Tax Act, may
be liable to pay an additional refundable tax of 6 2/3% on certain investment income,
including taxable capital gains and interest.



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> Tax-Exempt Unitholders

Provided that the Trust qualifies as a "mutual fund trust" or
is a "registered investment" for purposes of the Tax Act at a particular time,
the trust units will be qualified investments for Exempt Plans. If the Trust ceases to
qualify as a mutual fund trust and the Trust's registration as a registered investment
under the Tax Act is revoked, the trust units will cease to be qualified investments under
the Tax Act for Exempt Plans. Where, at the end of a month, an Exempt Plan holds trust
units or other properties that are not qualified investments, the Exempt Plan may, in
respect of that month, be required to pay a tax under Part XI.1 of the Tax Act.

Exempt Plans will generally not be liable for tax in respect of any
distributions received from the Trust or any capital gain arising on the disposition of
trust units. However, where an Exempt Plan receives trust property as a result of a
redemption of trust units, some or all of such property may not be qualified investments
under the Tax Act for the Exempt Plans and could, as discussed above, give rise to adverse
consequences to the Exempt Plans (and, in the case of registered retirement savings plans
or registered retirement income funds, to the annuitants thereunder). Accordingly, Exempt
Plans that own trust units should consult their own tax advisors before deciding to
exercise their redemption rights thereunder.

Based on Enterra's certificate as to certain factual matters, provided
that the Trust is a "mutual fund trust" and restricts its holdings of foreign
property within the limits provided under the Tax Act (30% based on cost in 2003), or the
Trust is a "registered investment" within the meaning of the Tax Act (see
"Taxation of the Trust" above), the trust units will not constitute foreign
property for Exempt Plans, registered pension funds or plans or other persons subject to
tax under Part XI of the Tax Act. Registered education savings plans are not subject to
tax under Part XI of the Tax Act.

Taxation of Capital Gains and Capital Losses

Generally, one half of any capital gain (a "taxable capital
gain") realized by a unitholder or a unitholder on the disposition of capital
property in a taxation year must be included in the income of the holder for the year, and
one half of any capital loss (an "allowable capital loss") realized in a
taxation year may be deducted from taxable capital gains realized by the holder in that
year. Allowable capital losses for a taxation year in excess of taxable capital gains for
that year generally may be carried back and deducted in any of the three preceding
taxation years or carried forward and deducted in any subsequent taxation year against net
capital gains realized in such years, to the extent and under the circumstances described
in the Tax Act.

A corporation that is throughout a relevant taxation year a
"Canadian-controlled private corporation", as defined in the Tax Act, may be
liable to pay an additional refundable tax of 6 2/3% on certain investment income,
including taxable capital gains realized in the particular taxation year.

Capital gains realized by an individual may give rise to a liability
for alternative minimum tax.

Non-Residents of Canada

This portion of the summary is applicable to a unitholder who, for the
purposes of the Tax Act, and at all relevant times is not resident in Canada and is not
deemed to be resident in Canada, does not use or hold, and is not deemed to use or hold,
trust units in, or in the course of, carrying on business in Canada, and is not an insurer
who carries on an insurance business in Canada and elsewhere (a "Non-Resident
Holder").

Taxation of the Trust

The tax treatment of the Trust under the Tax Act is as generally
described above under "Residents of Canada  Taxation of the Trust". If the
Trust ceases to qualify as a mutual fund trust for purposes of the Tax Act, the Trust may
be required to pay tax under Part XII.2 of the Tax Act. The payment of Part XII.2 tax by
the Trust may have adverse tax consequences to certain unitholders.

Taxation of Income from Trust Units

All income of the Trust determined in accordance with the Tax Act
(except taxable capital gains) paid or credited by the Trust in a taxation year to a
Non-Resident Holder will generally be subject to Canadian withholding tax at a rate of
25%, subject to a reduction of such rate under an applicable income tax treaty or
convention, whether such income is paid or credited in cash or in Reinvested trust units.
See "Residents of Canada  Taxation of the Trust" above. Provided
that certain conditions are satisfied, the rate of Canadian withholding tax may be reduced
to nil in respect of amounts that are paid or credited by the Trust to a Non-Resident
Holder as income of or from the Trust where the amount that can reasonably be regarded as
being derived from interest that would not have been subject to Canadian withholding tax
under the Tax Act had the interest been paid directly to the Non-Resident Holder instead
of to the Trust.



- 59 -

Taxable capital gains realized by the Trust and paid or payable by the
Trust in a taxation year to a Non-Resident Holder will generally be deemed to be taxable
capital gains of the Non-Resident Holder from the disposition of capital property and may
be subject to tax under the Tax Act. See "Taxation of Capital Gains and Capital
Losses on Dispositions of Taxable Canadian Property" above.

The cost to a Non-Resident Holder of a trust unit will generally
include all amounts paid by the Non-Resident Holder for the trust unit. Reinvested trust
units issued to a Non-Resident Holder as a non-cash distribution of income will have a
cost equal to the amount of income distributed by the issuance of such Reinvested trust
units for purposes of the Tax Act. This cost will be averaged with the adjusted cost base
of all other trust units held by the Non-Resident Holder as capital property in order to
determine the respective adjusted cost base of each trust unit.

Disposition of trust units

Upon a redemption of trust units, a Non-Resident Holder will be subject
to Canadian withholding tax at a rate of 25%, subject to reduction under any applicable
tax treaty or convention, of the amount that is the Non-Resident Holder's share of taxable
capital gains realized by the Trust as a result of the redemption (other than taxable
capital gains that are paid or payable to the Non-Resident Holder by the Trust under the
Tax Act) and of any accrued interest on the Series A Notes that is transferred to the
Non-Resident Holder on the redemption.

Taxable capital gains realized by the Trust on a disposition of Series
A Notes to a Non-Resident Holder on a redemption of trust units, which are paid or payable
by the Trust in a taxation year to a Non-Resident Holder will generally be deemed to be
taxable capital gains of the Non-Resident Holder from the disposition of capital property
and may be subject to tax under the Tax Act. See "Taxation of Capital Gains and
Capital Losses on Dispositions of Taxable Canadian Property" below.

A Non-Resident Holder will be subject to taxation in Canada in respect
of a capital gain or capital loss realized on the disposition of trust units only to the
extent such units constitute "taxable Canadian property", as defined in the Tax
Act, and the Non-Resident Holder is not afforded relief under an applicable income tax
treaty or convention.

trust units will normally not be taxable Canadian property at a
particular time provided that (i) the Non-Resident Holder, persons with whom the
Non-Resident Holder does not deal at arm's length (within the meaning of the Tax Act), or
the Non-Resident Holder together with such persons, did not own or have an interest in or
option in respect of 25% or more of the issued trust units at any time during the 60-month
period preceding the particular time (ii) the Trust is a mutual fund trust at the time of
the disposition, and (iii) the trust units are not otherwise deemed to be taxable Canadian
property.

A Non-Resident Holder of trust units that are not taxable Canadian
property will not be subject to tax under the Tax Act on the redemption or disposition of
such units.

A Non-Resident Holder whose trust units
constitute taxable Canadian property generally will realize a capital gain (or capital
loss) on the redemption or disposition of such units equal to the amount by which the
proceeds of disposition exceeds (or is less than) the aggregate of (i) such unitholder's
adjusted cost base of its trust units so redeemed or disposed, determined immediately
before the redemption or disposition and (ii) any reasonable costs of disposition. A
redemption of trust units in consideration for cash distributed to the Non-Resident Holder
in satisfaction of the Market Redemption Price, or the issuance of a Redemption Note by
the Trust in satisfaction of the Market Redemption Price, will be a disposition of such
trust units for proceeds of disposition equal to the cash or the principal amount of the
Redemption Note, as the case may be. Where trust units are redeemed by the distribution of
Series A Notes to the Non-Resident Holder, the proceeds of disposition to the Non-Resident
Holder of such trust units will generally be equal to the fair market value of the Series
A Notes so distributed less any capital gain or income realized by the Trust in connection
with such redemption which has been designated by the Trust to the redeeming unitholder.

Where a Non-Resident Holder that is a corporation or a trust (other
than a mutual fund trust) disposes of a trust unit, the Non-Resident Holder's capital loss
from the disposition will generally be reduced by the amount of dividends from taxable
Canadian corporations previously designated by the Trust to the unitholder, except to the
extent that a loss on a previous disposition of a trust unit has been reduced by such
dividends. Similar rules apply where a corporation or trust (other than a mutual fund
trust) is a member of a partnership that disposes of trust units. See "Taxation of
Capital Gains and Capital Losses on Dispositions of Taxable Canadian Property"
below.

The cost to a Non-Resident Holder of any Series A Notes distributed to
the Non-Resident Holder by the Trust on a redemption of trust units will be equal to the
fair market value of such Series A Notes at the time of distribution, excluding any
accrued interest thereon.



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Taxation of Capital Gains and Capital Losses
on Dispositions of Taxable Canadian Property

Generally, one half of any capital gain (a "taxable capital
gain") realized by a Non-Resident Holder on a disposition of taxable Canadian
property in a taxation year must be included in the income of the Non-Resident Holder for
the year, and one half of any capital loss (an "allowable capital loss")
realized by a Non-Resident Holder on a disposition of taxable Canadian property in a
taxation year may be deducted from taxable capital gains realized by the Non-Resident
Holder in that year. Allowable capital losses for a taxation year in excess of taxable
capital gains for that year generally may be carried back and deducted in any of the three
preceding taxation years or carried forward and deducted in any subsequent taxation year
against net capital gains realized in such years, to the extent and under the
circumstances described in the Tax Act.

In certain cases where a Non-Resident Holder realizes a capital gain
from a disposition of property that constitute taxable Canadian property to such
Non-Resident Holder, it is possible that any such capital gain may be exempt from tax for
the purposes of the Tax Act by virtue of the provisions of an income tax treaty or
convention between Canada and the country of residence of the Non-Resident Holder.
Conversely, the amount of any capital loss resulting from the disposition of such property
may not be deductible against capital gains of the Non-Resident Holder for the purposes of
the Tax Act by virtue of the provisions of such income tax treaty or convention.
unitholders who are Non-Resident Holders are advised to consult with their tax advisors
regarding the application of any applicable income tax treaty or convention.

If a Non-Resident Holder disposes of taxable Canadian property, the
Non-Resident Holder is required to file a Canadian income tax return for the taxation year
in which such disposition occurs.

United States Federal Income Tax Considerations

The following summary discusses the material United States federal
income tax considerations that are generally applicable to a holder of Enterra common
shares and trust units who is a citizen or resident of the United States, who is a
corporation, partnership or other entity that is created or organized in or under the laws
of the United States, who is subject to United States federal income tax on a net income
basis with respect to Enterra common shares or who will be subject to United States
federal income tax on a net income basis with respect to trust units that are acquired (a
"U.S. Holder'').

This summary does not purport to be a complete description of all of
the United States federal income tax considerations that may be relevant to a U.S. Holder.
In particular, this summary deals only with U.S. Holders who hold Enterra common shares as
a capital asset. This summary does not address the tax treatment of U.S. Holders who are
subject to special tax rules. Nor does this summary discuss the United States federal
income tax considerations for a partner in a partnership which holds Enterra common shares
or trust units.

Flow-through of Items of Income, Gain, Loss, Deduction and Credit

A U.S. holder will include in each of its taxable years its share of
our items of income, gain, loss, deduction and credit and certain deductions in respect of
depletion for each of our taxable years that ends within or with such U.S. holder's
taxable year on its own United States federal income tax return in order to determine its
liability for United States federal income tax whether or not we make any distribution to
it. Such items of income, gain, loss, deduction and credit will be determined on United
States federal income tax principles and will as a general matter retain their character
and source as they flow through us to the holders of trust units. The use by a holder of
trust units of certain of our items of deduction, loss and credit will be limited as is
discussed below.



after the close of its taxable year but before the end of our taxable
year will be required to include in income for its then taxable year its share of more
than one year of our items of income, gain, loss, deduction and credit. A U.S. Holder's
share of our items of income, gain, loss, deduction and credit will, as a general matter,
be its percentage interest in us of such items..

Tax Rates and Creditability of Certain Canadian Income Taxes.

As general matter, the character and source of a U.S. holder's share of
the items of the income, gain, loss, deduction and credit is determined at our level and
flows through us to each such U.S. holder in determining its liability for United States
federal income tax including any effect of the alternative minimum tax. Each U.S. holder
should consult with its tax advisors as to the impact of holding trust units on its
liability for the United States federal income tax and the alternative minimum tax. The
rules as to the use of foreign income taxes as credits are complex, the following
discussion is only a summary of a portion thereof, and a U.S. holder should discuss these
matters with its own tax advisors.



-

United States Federal Income Tax Rates

A U.S. holder's share of our oil and gas production is treated as
ordinary income subject to cost depletion. Such ordinary income is generally subject to
the income tax at a maximum rate of 35 percent. Dividends that are received from a foreign
corporation are currently subject to the United States federal income tax at a maximum
rate of 15 percent under certain conditions. If a U.S. holder who is an individual, then
any dividends received would be subject to the United States federal income tax at a
maximum rate of 15 percent so long as (i) the shares in respect of which the dividends are
paid have been held (subject to certain tolling rules) for more than 60 days during the
120 day period which begins 60 days before the those shares go ex-dividend, (ii) such U.S.
holder is not under an obligation to make certain related payments with respect to
substantially similar or related property, (iii) we are not either a foreign personal
holding company, a foreign investment company or a passive foreign investment company, and
(iv) we are eligible for the benefits of the income tax treaty between Canada and the
United States. It is likely that the Internal Revenue Service will take the position that
such holding period requirement is applied when an individual holds shares indirectly
through us to the individual's holding period in trust units.

For a U.S. holder who is an individual, any long-term capital gain that
is realized on the sale or other disposition of trust units (including any part of a
distribution that is treated as gain on such shares that is a long-term capital gain)
would be subject to tax at a maximum rate of 15 percent until the end of 2008 under
current law. Each U.S. holder should discuss with its own advisor whether a person whose
holding period in us is less than one year can claim such 15 percent tax rate.

Credits for Canadian Income Taxes

As a general matter, any Canadian income taxes that are withheld from
distributions are foreign income taxes that, subject to generally applicable limitations
under United States law, may be used by a U.S. holder as a credit against its United
States federal income tax liability or as a deduction (but only for a taxable year for
which such U.S. holder elects to do so with respect to all foreign income taxes). So long
as we are a partnership for United States federal income tax purposes, the provisions of
Section 901(k) of the Internal Revenue Code should not apply. If we were a corporation for
such purposes, then a U.S. Holder would not be able to claim the foreign tax credit with
respect to any such Canadian tax that is withheld on a distribution that we made unless
such U.S. holder had held the trust units for a minimum period (subject to certain tolling
rules) of at least 16 days during the 30 day period beginning on the date which is 15 days
before the date on which the trust units went ex-dividend with respect to such dividend or
to the extent such U.S. holder is under an obligation to make related payments with
respect to substantially similar or related property. It is likely that the Internal
Revenue Service will take the position that the holding period requirement that is
summarized in the preceding sentence is measured as to an individual partner of us in
respect of any Canadian taxes paid by us in respect of dividends that we receive by the
holding period in the trust units.

The limitation under United States law on foreign taxes that may be
used as credits is calculated separately with respect to specific classes of income or
"baskets." That is, the use of foreign taxes that are paid with respect to
income in any such basket as a credit is limited to a percentage of the foreign source
income in that basket. For such purposes, a U.S. holder's share of our income, gain, loss
and deductions is generally in the passive basket if it holds less than 10 percent of the
trust units. Its share of the dividends and the income will be from foreign sources, but
the amount of foreign source income of an individual is only a fraction of the dividend
income that is subject to the 15 percent maximum rate. Under rules of general application,
a portion of a U.S. holder's interest expense and other expenses can be allocated to, and
thereby reduce, the foreign source income in any basket.





Although we do not expect to be a passive foreign investment company,
or PFIC, it will be a PFIC if either (a) 75 percent or more of its gross income in a
taxable year, including the pro rata share of the gross income of any company, U.S. or
foreign, in which it is considered to own 25 percent or more of the shares by value, is
passive income (as defined in the pertinent provisions of the Internal Revenue Code or (b)
50 percent or more of its assets (including the pro rata share of the assets of any
company in which it is considered to own 25 percent or more of the shares by value), are
held for the production of, or produce, passive income. Although we believe that we are
not currently a PFIC and do not expect that we will become a PFIC, there is no assurance
in that regard.



If we were a PFIC, and a U.S. holder did not make an election to treat
it as a qualified electing fund (there is no assurance that it will be able to make such
an election) or elect to make a mark-to-market election (again, there is no assurance that
it will be able to make such an election) then distributions on our stock that exceed 125
percent of the average distributions received by the U.S. holder in the shorter of the
three previous taxable years or the U.S. holder's holding period for the trust units
before the taxable year of distribution and the entire amount of gain that is realized by
a U.S. holder upon the sale of the trust units would be subject to an additional United
States income tax that approximates (and in some cases exceeds) the value of presumed
benefit of a deferral of United States income taxation that was available because we are a
foreign corporation.

Tax-Exempt Organizations and Other Investors



Employee benefit plans and most other organizations exempt from federal
income tax, including individual retirement accounts and other retirement plans, are
subject to federal income tax on unrelated business taxable income. We are unable to
provide any assurance that the income that we recognize in respect of the royalty or in
respect of any of our other assets will not be unrelated business taxable income.

A regulated investment company or "mutual fund" (as such
terms are used in the Internal Revenue Code) is required in order to maintain its special
status under the Internal Revenue Code to derive 90 percent or more of its gross income
from interest, dividends and gains from the sale of stocks or securities or foreign
currency or specified related sources. A significant amount of our gross income may not be
any such type of income.

Administrative Matters



We expect to furnish to each unitholder, within 90 days after the close
of each calendar year, specific tax information, including a Schedule K-1, which describes
the unitholders share of our income, gain, loss, deduction and credits for the
preceding taxable year. In preparing this information, which will not be reviewed by tax
counsel, we will take various accounting and reporting positions, some of which have been
mentioned earlier, to determine the share of income, gain, loss and deduction. We cannot
assure you that those positions will yield a result that conforms to the requirements of
the Internal Revenue Code Treasury regulations or administrative interpretations of the
Internal Revenue Service. Any challenge by the Internal Revenue Service could negatively
affect the value of the trust units.

The Internal Revenue Service may audit our federal income tax
information returns. Adjustments resulting from an Internal Revenue Service audit may
require each unitholder to adjust a prior year's tax liability, and possibly may result in
an audit of its return. Any audit of a unitholder's return could result in adjustments not
related to our returns. Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of administrative adjustments by the
Internal Revenue Service and tax settlement proceedings.

The tax treatment of partnership items of income, gain, loss and
deduction are determined in a partnership proceeding rather than in separate proceedings
with the partners. The Internal Revenue Code requires that one partner be designated as
the "Tax Matters Partner" for these purposes. The Tax Matters Partner will make
some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters
Partner can extend the statute of limitations for assessment of tax deficiencies against
unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with
less than a one percent profits interest in us to a settlement with the Internal Revenue
Service unless that unitholder elects, by filing a statement with the Internal Revenue
Service, not to give that authority to the Tax Matters Partner. The Tax Matters Partner
may seek judicial review, by which all the unitholders are bound, of a final partnership
administrative adjustment and, if the Tax Matters Partner fails to seek judicial review,
judicial review may be sought by any unitholder having at least one percent interest in
profits or by any group of unitholders having in the aggregate at least a five percent
interest in profits. However, only one action for judicial review will go forward, and
each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the Internal Revenue Service
identifying the treatment of any item on its federal income tax return that is not
consistent with the treatment of the item on our return. Intentional or negligent
disregard of this consistency requirement may subject a unitholder to substantial
penalties.



- 63 -

Nominee Reporting

Persons who hold an interest trust units as a nominee for another
person are required to furnish to us:

> the name, address and taxpayer identification number of the beneficial
>     owner and the nominee;
>     whether the beneficial owner is:
>     (i)a person that is not a United States person;
>         (ii) a foreign government, an international organization or any wholly
>         owned agency or instrumentality of either of the foregoing; or
>         (iii) a tax-exempt entity;
>     the amount and description of trust units held, acquired or transferred
>     for the beneficial owner; and
>     specific information including the dates of acquisitions and transfers
>     means of acquisitions and transfers, and acquisition cost for purchases, as well as the
>     amount of net proceeds from sales.

Brokers and
financial institutions are required to furnish additional information, including whether
they are United States persons and specific information on the trust units they acquire,
hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of
$100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report
that information to us. The nominee is required to supply the beneficial owner of the
trust units with the information furnished to us.

Registration as a Tax Shelter

The Internal Revenue Code requires that "tax shelters" be
registered with the Secretary of the Treasury. Although we may not be a "tax
shelter" for such purposes, we have applied to register as a "tax shelter"
with the Secretary of the Treasury in light of the substantial penalties that might be
imposed if registration is required and not undertaken.

Issuance of a tax shelter registration number does not indicate that
investment in us or the claimed tax benefits have been reviewed, examined or approved by
the Internal Revenue Service.

We will supply our tax shelter registration number to you when one has
been assigned to us. A unitholder who sells or otherwise transfers a trust unit in a later
transaction must furnish the registration number to the transferee. The penalty for
failure of the transferor of a unit to furnish the registration number to the transferee
is $100 for each failure. A unitholder must disclose our tax shelter registration number
on its tax return on which any deduction, loss or other benefit we generates is claimed or
on which any of our income is included. A unitholder who fails to disclose the tax shelter
registration number on its return, without reasonable cause for that failure, will be
subject to a $250 penalty for each failure. Any penalties discussed are not deductible for
federal income tax purposes.



Certain Treasury regulations require taxpayers to report specific
information on Internal Revenue Service Form 8886 if they participate in a
"reportable transaction." A transaction may be a reportable transaction based
upon any of several factors, including the existence of book-tax differences common to
financial transactions, one or more of which may be present with respect to your
investment in the trust units. Investors should consult their own tax advisor concerning
the application of any of these factors to an investment in the trust units. Congress is
considering legislative proposals that, if enacted, would impose significant penalties for
failure to comply with these disclosure requirements.

Other Tax Considerations

Each U.S. holder is urged to investigate the legal and tax
consequences, under the laws of pertinent jurisdictions, of acquiring and holding the
trust units. Accordingly, each prospective unitholder is urged to consult its tax counsel
or other advisor with regard to those matters. Further, it is the responsibility of each
unitholder to file all state, local and foreign, as well as United States federal tax
returns that may be required.



Not Applicable

- 64 -



Not Applicable

H. Documents on Display

Any statement in this annual report about any of our contracts or other
documents is not necessarily complete. If the contract or document is filed as an exhibit,
the contract or document is deemed to modify the description contained in this
registration statement. You must review the exhibits themselves for a complete description
of the contract or document.

We intend to provide our unitholders with annual reports containing
consolidated financial statements audited by an independent chartered accounting firm and
will make available to unitholders quarterly reports containing unaudited consolidated
financial data for the first three quarters of each year. We are subject to the
information and reporting requirements of the Securities and Exchange Act of 1934 and file
periodic reports, proxy statements and other information with the SEC. However, we are
exempt from the rules under the Exchange Act prescribing the furnishing and content of
proxy statements, and our officers, directors and principal stockholders are exempt from
the reporting and short-swing profit recovery provisions contained in Section 16 of the
Exchange Act. Under the Exchange Act, we are not required to publish financial statements
as frequently or as promptly as U.S. companies. Such reports, proxy statements and other
information filed with the SEC may be inspected at the public reference facilities
maintained by the Commission at Judiciary Plaza, 450 5th Street N.W., Washington, D.C.
20549. Copies of these materials may be obtained at prescribed rates from the Commission
at that address. The reports, proxy statements and other information can also be inspected
on the Commissions Web site at

If you are a unitholder, you may request a copy of these
filings at no cost by contacting us at:



Enterra Energy Trust

Suite 2600, 500  4th Avenue S.W.

Calgary, Alberta, Canada

T2P 2V6

(403) 213-2502

I. Subsidiary Information

Not Applicable

Item 11. Qualitative and Quantitative Disclosures about Market Risk

We are exposed to al of the normal risks inherent within the oil and gas sector,
including commodity price risk, foreign-currency rate risk, interest rate risk and credit
risk. We manage our operations in a manner intended to minimize our exposure, as described
in notes 12 and 13 to the consolidated financial statements.

Credit Risk

Credit risk is the risk of loss resulting from non-performance of
contractual obligations by a customer or joint venture partner. A substantial portion of
our accounts receivable are with customers in the energy industry and are subject to
normal industry credit risk. We assess the financial strength of our customers and joint
venture partners through regular credit reviews in order to minimize the risk of
non-payment.

Foreign Exchange Risk

We are exposed to market risk from changes in the exchange rate between
U.S. and Canadian dollars. The price we receive for oil and natural gas production is
based on a benchmark expressed in U.S. dollars, which is the standard for the oil and
natural gas industry worldwide. Our monthly distributions are also based on a value
expressed in U.S. dollars. However, we pay our operating expenses, drilling expenses and
general overhead expenses in Canadian dollars. Changes to the exchange rate between U.S.
and Canadian dollars can adversely affect us. When the value of the U.S. dollar increases,
we receive higher revenue and when the value of the U.S. dollar declines, we receive lower
revenue on the same amount of production sold at the same prices. A change of $0.01 in the
U.S. to CDN dollar would impact Enterras earnings by approximately $193,000 and its
cash flow by $394,000.



Commodity Price Risk

Our financial condition, results of operations and capital resources
are highly dependent upon the prevailing market prices of oil and natural gas. These
commodity prices are subject to wide fluctuations and market uncertainties due to a
variety of factors that are beyond our control. Factors influencing oil and natural gas
prices include the level of global demand for crude oil, the foreign supply of oil and
natural gas, the establishment of and compliance with production quotas by oil exporting
countries, weather conditions which determine the demand for natural gas, the price and
availability of alternative fuels and overall economic conditions. It is impossible to
predict future oil and natural gas prices with any degree of certainty. Sustained weakness
in oil and natural gas prices may adversely affect our financial condition and results of
operations, and may also reduce the amount of oil and natural gas reserves that we can
produce economically. Any reduction in our oil and natural gas reserves, including
reductions due to price fluctuations, can have an adverse affect on our ability to obtain
capital for our development activities. Similarly, any improvements in oil and natural gas
prices can have a favorable impact on our financial condition, results of operations and
capital resources. If the WTI oil price were to change by US$1.00 per bbl, the impact on
Enterras earnings would be approximately $869,000 and the impact on Enterras
cash flow would be approximately $1,774,000. If natural gas prices were to change by
US$0.50 per mcf, the impact on Enterras earnings would be approximately $873,000 and
the impact on Enterras cash flow would be approximately $1,781,000.

We periodically use hedges with respect to a portion of our oil and
natural gas production to mitigate our exposure to price changes. While the use of these
derivative arrangements limits the downside risk of price declines, such use may also
limit any benefits which may be derived from price increases.



Interest Rate Risk

Interest rate risk exists principally with respect to our indebtedness
that bears interest at floating rates. At December 31, 2003, we had $34 million of
indebtedness bearing interest at floating rates. If interest rate were to change by on
full percentage point, the net impact on Enterras earnings would be approximately
$244,000 and the net impact on Enterras cash flow would be approximately $337,000.

Summarized below are Enterras sensitivities to various risks, based on its 2003
operations:

Sensitivities
    Estimated
    2004 impact on:Net Income
    Cash FlowCrude oil  US$1.00/bbl change in WTI
    $869,000
    $1,774,000Natural Gas  US$0.50/mcf change
    $873,000
    $1,781,000Foreign Exchange - $0.01 change in U.S. to CDN
    dollar
    $193,000
    $394,000Interest
    rate  1% change
    $244,000
    $337,000




Item 12. Description of Securities Other Than Equity Securities.

> Not Applicable

Part II

Item 13. Defaults, Dividends Arrearages and Delinquencies

None

Item 14. Material Modifications to the Rights of Security Holders and
Use of Proceeds

Not Applicable

Item 15. Controls and Procedures

(a) Evaluation of disclosure controls and procedures. 
Our Chief Executive Officer and Chief Financial Officer, after evaluating the
effectiveness of  Enterras disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) as of the end of the period covered by this report
(the "Evaluation Date"), have concluded that, as of the Evaluation Date, our
disclosure controls and procedures were adequate and effective to ensure that material
information relating us and our consolidated subsidiaries would be made known to them by
others within those entities.



- 66 -

(b) Changes in internal controls.  There were no
significant changes in our internal controls or in other factors that could significantly
affect our disclosure controls and procedures subsequent to the Evaluation Date, nor were
there any significant deficiencies or material weaknesses in such disclosure controls and
procedures requiring corrective actions.  As a result, no corrective actions were
taken.

Item 16. [Reserved]

Item 16A. Audit Committee Financial Expert

The chairman of our audit committee, William E. Sliney, possesses the
attributes required of an audit committee financial expert.

Item 16B. Code of Ethics

We have not yet adopted a Code of Ethics. We plan to formalize and
adopt a Code of Ethics that applies to all executive officers during the year ending
December 31, 2004.



Item 16C. Principal Accountant Fees and Services

Deloitte & Touche LLP have audited our annual financial
statements since our 2002 fiscal year. In addition, Deloitte & Touche LLP reviews
our interim financial statements commencing with the nine months ended September 30, 2002.
Deloitte & Touche LLP acted as our independent auditor for the fiscal years ended
December 31, 2003 and 2002.

The audit fees billed to us by Deloitte & Touche LLP for services performed in 2003
and 2002 were $170,900 and $52,500 respectively.

Audit Fees

Audit fees are fees billed for the audit of our annual consolidated
financial statements and for the reviews of our quarterly financial statements submitted
on Form 6-K. Additionally, audit fees include consents, reviews related to the
Information Circular and Proxy Statement and other services related to Canadian and SEC
matters.

Pre-Approval Policies and Procedures

The audit committee approves all audit, audit-related services, tax services and other
services provided by Deloitte & Touche LLP. Any services provided by
Deloitte & Touche LLP that are not specifically included within the scope of the
audit must be pre-approved by the audit committee in advance of any engagement. Under the
Sarbanes-Oxley Act of 2002, audit committees are permitted to approve certain fees for
audit-related services, tax services and other services pursuant to a de minimus exception
prior to the completion of an audit engagement. In 2003, none of the fees paid to
Deloitte & Touche LLP were approved pursuant to the de minimus exception.

Item 16D. Exemptions from the Listing Standards for Audit Committees.

Not Applicable.

Item 16E. Purchases of Equity Securities by the Issuer and Affiliated
Purchasers.

Not Applicable.

PART III

Item 17. Financial Statements

We have responded to Item 18 in lieu of responding to this item.



Item 18. Financial Statements

The Consolidated Financial Statements of Enterra Energy Trust are
attached as follows:

|Audited Annual Financial Statements:                                    | Page       
|----------------------------------------------------------------------- | -----------
|Reports of Deloitte & Touche LLP and KPMG
    LLP, Independent Auditors | F-1 and F-2
|Consolidated Balance Sheets                                             | F-3        
|Consolidated Statements of
    Earnings and Accumulated Earnings        | F-4        
|Consolidated
    Statements of Cash Flows                               | F-5        
|Notes to
    Consolidated Financial Statements                          | F-6 to F-30

Item 19. Exhibits

Number Exhibit

|2.1  | Amalgamation Agreement
    dated May 27, 1998 between Temba Resources Ltd. and PTR Resources Ltd. pursuant to which
    the Registrant was amalgamated under the Business Corporations Act (Alberta) on June 30,
    1998.
|---- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.2  | Letter Agreement dated
    August 12, 1999 pursuant to which the Registrant acquired all of the issued and
    outstanding shares of 759795 Alberta Ltd.                                                                  
|2.3  | Notice of Intention to File
    a Normal Course Issuer Bid.                                                                                                                                                               
|3.1  | Certificate of Amalgamation
    and attached Articles of Amalgamation of the Registrant dated and filed June 30, 1998.                                                                                                    
|3.2  | By-laws of the Registrant.                                                                                                                                                                                                
|3.3  | Enterra Energy Trust
    Amended And Restated Trust Indenture (1)                                                                                                                                                         
|4.1  | Form of Warrant Trust
    Indenture between the Registrant and Montreal Trust Company of Canada providing for the
    issuance of the Warrants.                                                                           
|4.2  | Form of Warrant Agreement
    between the Registrant and the Representatives providing for the issuance of the
    Underwriters' Warrants.                                                                                
|10.1 | Credit Facility Letter
    Agreement between the Alberta Treasury Branches and the Registrant as Borrower dated April
    19, 2000.                                                                                       
|10.2 | Promissory Notes dated June
    5, 2000 granted by Westlinks to each of Glenn Russell, Patrick Williams Advisors, William
    J. Gordica, F. Jack Wright, Lawrence W. Underwood and Sapphire Capital Inc.                 
|10.3 | Purchase and Sale Agreement
    dated April 6, 2000 between Sabre Exploration Ltd. and the Registrant.                                                                                                                    
|10.4 | Purchase and Sale Agreement
    dated October 1, 2000 between the Registrant and Compton Petroleum Corporation.                                                                                                           
|10.5 | Consulting Agreement dated
    October 13, 2000 between Westlinks Resources Ltd. and Wells Gray Resort & Resources
    Ltd.                                                                                               
|10.6 | Arrangement Agreement among
    Westlinks Resources Ltd. and 3779041Canada Ltd. and Big Horn Resources Ltd.                                                                                                               
|10.7 | Information Circular and
    Proxy Statement for the Plan of Arrangement between Big Horn Resources Ltd. and Westlinks
    Resources Ltd.                                                                                 
|12.1 | Certifications of Chief
    Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act                                                                                                                           
|12.2 | Certifications of Chief
    Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act                                                                                                                           
|13.1 | Certifications of Chief
    Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act                                                                                                                           
|13.2 | Certifications of Chief
    Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act                                                                                                                           
|(1)  | the description of our
    trust units contained in our amendment to our registration statement on Form 8-A12G/A
    dated November 28, 2003                                                                              









Enterra Energy Trust

By: Enterra Energy Corp.

Administrator of the Trust



By: /s/ Luc Chartrand

Name: Luc Chartrand

Title: Chief Executive Officer

April 26, 2004







Auditors Report



To the Unitholders of Enterra Energy Trust:

We have audited the consolidated balance sheets of Enterra
Energy Trust (formerly Enterra Energy Corp.) as at December 31, 2003 and 2002 and the
consolidated statements of earnings and accumulated earnings and cash flows for the years
then ended.  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 auditing standards generally accepted in Canada and in the United States
of America.  These standards require that we plan and perform an audit to obtain
reasonable assurance 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, these consolidated
financial statements present fairly, in all material respects, the financial position of
Enterra Energy Trust as at December 31, 2003 and 2002 and the results of its operations
and its cash flows for the years then ended in accordance with Canadian generally accepted
accounting principles.

The consolidated financial statements for
the year ended December 31, 2001 were audited by other auditors who expressed an opinion
without reservation on those consolidated financial statements in their report dated March
6, 2002.

(signed) Deloitte & Touche LLP

Chartered Accountants

Calgary, Canada

March 5, 2004

**Comments by Auditor on
Canada-United States of America Reporting Difference**

In the United States of America, reporting standards for
auditors also require the addition of an explanatory paragraph (following the opinion
paragraph) outlining changes in accounting principles that have been implemented in the
financial statements.  As discussed in Note 2f to the financial statements, the Trust
changed its method of accounting for stock-based compensation to conform to the new
Canadian Institute of Chartered Accountants Handbook recommendations Section 3870. 
Our report to the Unitholders, dated March 5, 2004, is expressed in accordance with
Canadian reporting standards which do not require a reference to such changes in
accounting principles in the auditors report when the change is properly accounted
for and adequately disclosed in the financial statements.

(signed) Deloitte & Touche LLP

Chartered Accountants

Calgary, Canada March 5, 2004

F-1



Auditors Report

We have audited the consolidated statements of earnings and
retained earnings and cash flows of Enterra Energy Corp for the year ended December 31,
2001. 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 audits in accordance with Canadian generally
accepted auditing standards and auditing standards generally accepted in the United States
of America. Those standards require that we plan and perform an audit to obtain reasonable
assurance 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 may by management, as well as evaluating the overall financial
statement presentation.

In our opinion, these consolidated financial statements present
fairly, in all material respects, the Companys operations and cash flows for the
year ended December 31, 2001 in accordance with Canadian generally accepted accounting
principles.

Canadian generally accepted accounting principles vary in
certain significant respects from accounting principles generally accepted in the United
States. Application of accounting principles generally accepted in the United States would
have affected the results of operations for the year ended December 31, 2001to the extent
summarized in note 17 to the consolidated financial statements.

(signed) KPMG LLP

Chartered Accountants

Calgary, Canada

March 6, 2002

F-2



|Enterra Energy Trust                                           
|---------------------------------------------------------------
|Consolidated Balance Sheets                                    
|As at December 31                                              
|(Expressed in Canadian dollars)                                
|                                                               
|**Assets**                                                     
|**Current assets**                                             
|Cash                                                           
|Accounts receivable                                            
|Deposit on land purchase (note 16)                             
|Prepaid expenses and deposits                                  
|                                                               
|                                                               
|Property and equipment (note 4)                                
|Deferred financing charges                                     
|                                                               
|                                                               
|**Liabilities**                                                
|**Current liabilities**                                        
|Accounts payable and accrued liabilities (note
    5)          
|Distributions payable to unitholders                           
|Income taxes payable                                           
|Bank indebtedness (note 6)                                     
|Current portion of long-term debt (note 7)                     
|                                                               
|                                                               
|Provision for future abandonment and site
    restoration costs
|Future income tax liability (note 8)                           
|Long-term debt (note 7)                                        
|Deferred gain (note 13)                                        
|Series 1 preferred shares (note 11)                            
|                                                               
|                                                               
|**Unitholders Equity**                                        
|Unitholders capital (note 9)                                  
|Exchangeable shares (note 9)                                   
|Contributed surplus (note 9)                                   
|Accumulated earnings                                           
|Accumulated distributions                                      
|                                                               
|Hedging contracts (note 13)                                    
|Commitments and guarantees (notes 14 and 15)                   
|Subsequent events (note 16)                                    
|                                                               
|                                                               
|Approved on behalf of the Board:                               
|                                                               
|Reg Greenslade Director                                        
|See accompanying notes to consolidated
    financial statements

F-3



|Enterra Energy Trust                                            
|----------------------------------------------------------------
|Consolidated Statements of Earnings and
    Accumulated Earnings
|Years Ended December 31                                         
|(Expressed in Canadian dollars)                                 
|                                                                
|Revenue                                                         
|Oil and gas                                                     
|                                                                
|Expenses                                                        
|Royalties                                                       
|Production                                                      
|General and administrative                                      
|Interest                                                        
|Amortization of deferred financing charges                      
|Depletion, depreciation and future site
    restoration         
|                                                                
|Earnings before the following                                   
|Restructuring charges (note 1)                                  
|Gain on redemption of preferred shares (note
    11)            
|Earnings
    before income taxes                                
|Income taxes (note 8)                                           
|Current                                                         
|Future                                                          
|                                                                
|Net
    earnings                                                
|                                                                
|Accumulated earnings, beginning of year                         
|Accumulated earnings, end of year                               
|Earnings per unit/share (note 10)                               
|Basic                                                           
|Diluted                                                         
|                                                                
|                                                                
|See accompanying notes to consolidated
    financial statements 



F-4



|Enterra Energy Trust                                                                                                                                                                                     
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Consolidated Statements of Cash
    Flows                                                                                                                                                                
|Years Ended December 31                                                                                                                                                                                  
|(Expressed in Canadian dollars)                                                                                                                                                                          
|                                                                                                                                                                                                         
|Cash provided by (used in):                                                                                                                                                                              
|Operations                                                                                                                                                                                               
|Net earnings                                                                                                                                                                                             
|Add non-cash items:                                                                                                                                                                                      
|Depletion, depreciation and future
    site restoration                                                                                                                                                  
|Future income taxes                                                                                                                                                                                      
|Deferred gain                                                                                                                                                                                            
|Amortization of deferred gain                                                                                                                                                                            
|Amortization of deferred financing
    charges                                                                                                                                                           
|Gain on redemption of preferred
    shares                                                                                                                                                               
|Valuation of Warrants                                                                                                                                                                                    
|                                                                                                                                                                                                         
|Net change in non-cash working
    capital items:                                                                                                                                                        
|Accounts receivable                                                                                                                                                                                      
|Prepaid expenses and deposits                                                                                                                                                                            
|Accounts payable and accrued
    liabilities                                                                                                                                                             
|Income taxes payable                                                                                                                                                                                     
|                                                                                                                                                                                                         
|Financing                                                                                                                                                                                                
|Bank indebtedness                                                                                                                                                                                        
|Long-term debt                                                                                                                                                                                           
|Deferred financing charges                                                                                                                                                                               
|Redemption of preferred shares                                                                                                                                                                           
|Repurchase of shares                                                                                                                                                                                     
|Exercise of options and warrants                                                                                                                                                                         
|                                                                                                                                                                                                         
|Investing                                                                                                                                                                                                
|Property and equipment additions                                                                                                                                                                         
|Deposit on land purchase                                                                                                                                                                                 
|Acquisition of Big Horn Resources
    Ltd. (note 3)                                                                                                                                                      
|Proceeds on disposal of property
    and equipment                                                                                                                                                       
|Investments                                                                                                                                                                                              
|Future abandonment and site
    restoration costs                                                                                                                                                        
|                                                                                                                                                                                                         
|Increase (decrease) in cash                                                                                                                                                                              
|Cash, beginning of year                                                                                                                                                                                  
|Cash, end of year                                                                                                                                                                                        
|                                                                                                                                                                                                         
|During 2003, the Trust paid
    $1,748,932 (2002 - $1,235,872: 2001 - $589,169) of interest on long-term debt and bank
    indebtedness and $133,929 (2002 - $132,000: 2001 - $120,000) of capital taxes.
|                                                                                                                                                                                                         
|                                                                                                                                                                                                         
|See accompanying notes to
    consolidated financial statements                                                                                                                                          



F-5

> Enterra Energy Trust
>   Notes to Consolidated Financial Statements
>   For the Years Ended December 31,
>   2003, 2002 and 2001
>   (Expressed in Canadian Dollars)
>   1.    Structure of the Trust and basis of presentation
>   Enterra Energy Trust ("the Trust") was established on
>     November 25, 2003 under a Plan of Arrangement involving the Trust, Enterra Energy Corp.
>     ("Enterra"), Big Horn Resources Ltd. ("Big Horn"), Enterra Production
>     Partnership and Enterra Saskatchewan Ltd. ("Plan of Arrangement"). The Trust is
>     an open-end unincorporated investment trust governed by the laws of the Province of
>     Alberta and created pursuant to a trust indenture (the "Trust Indenture"). The
>     beneficiaries of the Trust are the holders of the Trust Units (the
>     "Unitholders").
>     Under the Plan of Arrangement, the shareholders of Enterra exchanged
>     their shares for two Trust Units of the Trust, which will pay monthly distributions, or
>     two Exchangeable Shares which may be exchanged into units of the Trust. Under the Plan of
>     Arrangement, Enterra Energy Corp. (the "Company") became a wholly-owned
>     subsidiary of the Trust, through amalgamation of Enterra, Big Horn Resources Ltd. and
>     Enterra Saskatchewan Ltd on November 25, 2003. The Company holds, on behalf of the Trust,
>     all the active oil and gas assets previously held by Enterra.
>     Prior to the implementation of the Plan of Arrangement on November 25,
>     2003, the consolidated financial statements included the accounts of Enterra and its
>     subsidiaries. After giving effect to the Plan of Arrangement, the consolidated financial
>     statements have been prepared on a continuity of interests basis which recognizes the
>     Trust as the successor entity to Enterra. Accordingly, these consolidated financial
>     statements reflect the financial position, results of operations and cash flows as if the
>     Trust, (together with its wholly owned subsidiary, the Company), had always carried on the
>     business formerly carried on by Enterra with all assets and liabilities recorded at the
>     carrying values of Enterra.
>     Restructuring costs associated with the Plan of Arrangement included
>     legal, accounting and advisory costs of $2,057,075 and employee bonus payments of
>     $3,699,000.
>     The restructuring charges in 2001 in the amount of $929,037 related to the
>     reorganization of Enterra by way of Plan of Arrangement in conjunction with the
>     acquisition of Big Horn as set out in note 3.

2.    Significant accounting policies

> These consolidated financial statements have been prepared in
>     accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The
>     impact of significant differences between Canadian GAAP and U.S. GAAP on these
>     consolidated financial statements is disclosed in note 17. These consolidated financial
>     statements include the accounts of the Trust, its wholly owned subsidiary Enterra Energy
>     Corp and its 100% partnership interest in Enterra Production Partnership (collectively the
>     "Trust" for purposes of the following notes to the financial statements). All
>     material intercompany accounts and transactions have been eliminated. Substantially all
>     exploration, development and production activities related to the Trusts oil and gas
>     business are conducted jointly with others and the accounts reflect only the Trusts
>     proportionate interest.
>     (a) Petroleum and natural gas properties
>     The Trust follows the "full cost" method of accounting for
>     petroleum and natural gas properties. All costs related to the exploration for and the
>     development of oil and gas reserves are capitalized into a single cost centre representing
>     the Trusts activity which is undertaken exclusively in Canada. Costs capitalized
>     include land acquisition costs, geological and geophysical expenditures, lease rentals on
>     undeveloped properties and costs of drilling productive and non-productive wells. Proceeds
>     from the disposal of properties are applied as a reduction of cost without recognition of
>     a gain or loss except where such disposals would result in a major change in the depletion
>     rate.

F-6

> 2.    Significant accounting policies (Continued)
>   Capitalized costs are depleted and depreciated using the
>     unit-of-production method based on the estimated gross proven oil and natural gas reserves
>     before royalties as determined by independent engineers. Units of natural gas are
>     converted into barrels of equivalents on a relative energy content basis. Costs related to
>     unproved properties are excluded from the costs subject to depletion until it is
>     determined whether or not proved reserves exist or if impairment has occurred.
>     The net amount at which petroleum and natural gas properties are
>     carried is subject to a cost recovery test (the "ceiling test"). Under this
>     test, capitalized costs, net of accumulated depletion and depreciation, are limited to
>     estimated future net revenues from proven reserves, based on year-end prices,
>     undiscounted, plus the net costs of major development projects and unproved properties,
>     less estimated future abandonment and site restoration costs, general and administrative
>     expenses, financing costs and income taxes. Any accumulated costs in excess of the
>     calculated ceiling test are charged to operations as a provision for impairment.
>     Estimated future abandonment and site restoration costs are provided
>     for over the life of proven reserves on a unit-of-production basis. The annual charge is
>     included in depletion and depreciation expense and actual abandonment and site restoration
>     costs are charged to the provision as incurred. The amounts recorded for depletion and
>     depreciation and the provision for future abandonment and site restoration costs are based
>     on estimates of proven reserves and future costs. The recoverable value of capital assets
>     is based on a number of factors including the estimated proven reserves and future costs.
>     By their nature, these estimates are subject to measurement uncertainty and the impact on
>     financial statements of future periods could be material.
>     (b) Income taxes
>     The Trust follows the liability method of accounting for future income
>     taxes. Under the liability method, future income tax assets and liabilities are determined
>     based on "temporary differences" (differences between the accounting basis and
>     the tax basis of the assets and liabilities) and are measured using the currently enacted,
>     or substantially enacted, tax rates and laws expected to apply when these differences
>     reverse. A valuation allowance is recorded against any future income tax assets if it is
>     more likely than not that the asset will not be realized. Income tax expense or benefit is
>     the sum of the Trusts provision for current income taxes and the difference between
>     the opening and ending balances of the future income tax assets and liabilities.
>     The Trust is a taxable entity under the Income Tax Act (Canada) and is
>     taxable only on income that is not distributed or distributable to the unitholders. As the
>     Trust allocates all of its taxable income to the unitholders in accordance with the Trust
>     Indenture, and meets the requirements of the Income Tax Act (Canada) applicable to the
>     Trust, no provision for income tax expense has been made in the Trust.
>     In the Trust structure, payments are made between the Company and the
>     Trust, which results in the transferring of taxable income from the Company to individual
>     unitholders. These payments may reduce future income tax liabilities previously reported
>     by the Company, which would be recognized as a recovery of income tax in the period
>     incurred.
>     (c) Financial instruments
>     The estimated fair value of all financial instruments is based on
>     quoted market prices and if not available, on estimates from third-party brokers or
>     dealers. The Trust uses financial instruments for non-trading purposes to manage
>     fluctuations in commodity prices, as described in note 13. Hedge accounting is used when
>     there is a high degree of correlation between price movements in the derivative instrument
>     and the item designated as being hedged. The Trust recognizes gains and losses in the same
>     period as the hedged item. If effective correlation ceases, hedge accounting is terminated
>     and future changes in the market value of the derivative instruments are included as gains
>     or losses in income in the period of change.

F-7

> 2.    Significant accounting policies (Continued)
>   (d) Estimates and assumptions
>     The preparation of financial statements in conformity with generally
>     accepted accounting principles requires management to make estimates and assumptions that
>     affect the reported amounts of assets and liabilities, and the disclosure of contingent
>     assets and liabilities at the dates of the financial statements and the reported amounts
>     of revenue and expenses during the reporting periods. Actual results could differ from
>     those estimates.
>     (e) Per unit amounts
>     Per unit amounts are calculated using the weighted average number of
>     units (or common shares to November 24, 2003) and reflect the two for one exchange ratio
>     pursuant to the Plan of Arrangement.
>     The Trust follows the treasury stock method to determine the dilutive
>     effect of options and other dilutive instruments. Under the treasury stock method, only
>     "in the money" dilutive instruments impact the diluted calculations.
>     (f) Unit-based compensation plan
>     Compensation cost for employees and directors is measured based on the
>     intrinsic value of the award at the date of the grant and is recognized over the vesting
>     period. Compensation cost for consultants is based on fair value and is expensed in the
>     financial statements with the offset to contributed surplus. Any consideration received by
>     the Trust on exercise of the unit rights will be credited to unitholders capital.
>     Effective January 14, 2004, the Trust adopted a unit based compensation plan for
>     employees, directors and consultants of the Trust.
>     Effective January 1, 2002 Enterra prospectively adopted the new
>     recommendations of the CICA with respect to the accounting for stock-based compensation
>     and other stock-based payments. In accordance with the new standard, the Trust elected to
>     continue its policy that no compensation be recorded on the granting of employee options
>     and consideration paid on the exercise of such options be recorded as shareholders
>     capital. In addition, the new standard requires a fair value based method of accounting
>     for other stock-based payments. See notes 9(f) and 9(g) for additional information with
>     regard to the methods and assumptions used in calculating the fair value of stock-based
>     compensation.
>     (g) Revenue recognition
>     Revenue from the sale of oil and gas is recognized based on volumes
>     delivered to customers at contractual delivery points and rates. The costs associated with
>     the delivery, including operating and maintenance costs, transportation and production
>     based royalty expenses are recognized in the same period in which the related revenue is
>     earned and recorded and are classified as part of production expenses.
>     (h) Deferred financing charges
>     Deferred financing charges include costs related to the proposed
>     financing mentioned in note 9(h) and costs related to capital leases due October 1, 2007
>     as described in note 7. These costs include professional and consulting fees, travel
>     costs, legal and accounting, and also include the $125,000 described in note 9(h). These
>     costs are amortized over the remaining life of their related financial instruments.
>     F-8
>   2.    Significant accounting policies (Continued)
>   (i) Comparative figures
>     The presentation of certain figures of the previous year has been
>     changed to conform with the presentation adopted for the current year.
>   3.    Business combination
>   Effective August 1, 2001 Enterra acquired 100% of the issued and
>     outstanding shares of Big Horn Resources Ltd. Details of the acquisition are as follows:

**Assets acquired:**Current assets, excluding
    cash
    $2,841,106Property and equipment
    46,874,34949,715,455Liabilities assumed:Current liabilities
    2,428,687Bank indebtedness
    8,950,000Provision for future
    abandonment and site restoration costs
    280,274Future income tax liability
    11,309,46422,968,425Net non-cash assets acquired
    26,747,030Cash acquired
    37,599$26,784,629Consideration:Cash
    $2,227,647Preferred
    shares (7,418,336 issued)
    6,305,586Common shares
    (3,496,436 issued)
    18,251,396$26,784,629


> The consideration value attributed to the common shares contemplates an
>     element related to the former stock options of Big Horn that were exchanged for stock
>     options of Enterra.  However, this element was not considered significant for
>     separate reporting.
>     
>     F-9
>   4.    Property and equipment

**Cost**
    **Accumulated**
    **depletion and**
    **depreciation**
    **2003 Net**Petroleum and natural gas
    properties
    $145,691,316
    $41,601,024
    $104,090,292Office furniture and equipment
    1,358,421
    627,428
    730,993$147,049,737
    $42,228,452
    $104,821,285**Cost**
    **Accumulated**
    **depletion and**
    **depreciation**
    **2004 Net**Petroleum and natural gas
    properties
    $112,657,277
    $18,897,024
    $93,760,253Office furniture and equipment
    1,077,988
    483,928
    594,060$113,735,265
    $19,380,952
    $94,354,313


> In conducting its ceiling test evaluation for 2003 the Trust followed
>     generally accepted accounting principles based on prices at December 31, 2003 of $34.07
>     per bbl of oil (2002 - $45.89) and $6.03 per mcf of gas (2002 - $5.49). No write-down was
>     required for 2003, 2002 or 2001.
>     Included in petroleum and natural gas properties are assets acquired
>     and pledged under capital lease agreements with a cost base of $5,217,500 and net book
>     value of $4,267,600 (2002 - $5,217,500 and $5,065,100).
>     Included in the cost of the petroleum and natural gas properties are
>     amounts for capitalized general and administrative expenses. These amounts were $1,787,000
>     in 2003 (2002 - $1,450,900: 2001 - $729,400).
>     At December 31, 2003 costs of undeveloped land of $5,037,000 (2002 - $3,967,000) were
>     excluded from the calculation of depletion expense.
>     The Trust estimates future abandonment and site restoration costs to be $3,240,000 at
>     December 31, 2003 (2002 - $4,114,000) of which $1,529,244 (2002 - $934,857) has been
>     accrued as a liability. The provision for site restoration and abandonment totaling
>     $704,800 (2002 - $232,500: 2001 - $242,000) is included as part of depreciation, depletion
>     and site restoration expense.
>   5.    Accounts payable and accrued liabilities

2003
    2002Trade accounts payable
    $7,808,042
    $13,762,437Other
    4,400,348
    6,898,568$12,208,390
    $20,661,005


> F-10
>   6.    Bank indebtedness
>   Bank indebtedness represents the outstanding balance under a line of
>     credit of $34,650,000 (2002 - $26,700,000). Drawings bear interest at 0.25% above the
>     banks prime lending rate (December 31, 2003 - 4.50%). Security is provided by a
>     first charge over all of the Trusts assets. The balance is repayable on demand.
>     While the loan is due on demand, the Trust is not subject to scheduled repayments.
>     Subsequent to year end, the line of credit was increased to $39,650,000.
>   7.    Long-term debt

Description
    2003
    2002Capital lease bearing interest at 8.605%,
    repayable monthly at $88,802 plus applicable taxes. The lease term is for 60 months, due
    October 1, 2007, with a purchase option of $1,000,000 and secured by the related
    equipment.
    $4,125,006
    $4,747,775Capital lease bearing interest at 12.15%,
    repayable monthly at $4,448 plus applicable taxes. The lease term is 24 months due
    December 19, 2004 with a purchase option of $100 and secured by the related equipment.
    43,542
    91,042Note payable bearing interest at 8%, repayable
    monthly at $7,190. The lease term is 15 months due December 20, 2003.
    -
    82,7814,168,548
    4,921,598Less current portion
    (782,930)
    (808,917)$3,385,618
    $4,112,681


> Interest expense includes $358,413 (2002 - $106,174, 2001 - $nil)
>     related to long-term debt.
>   8.    Income taxes
>   The income tax provision is calculated by applying Canadian federal
>   and provincial statutory tax rates to pre-tax income with adjustments as set out in the
>   following table:

2003
    2002
    2001Earnings before income
    taxes
    $7,079,030
    $6,020,401
    $2,299,055Combined federal and
    provincial income tax rate
    40.75%
    42.12%
    42.60%Computed income tax
    provision
    2,884,705
    2,535,793
    979,397Increase (decrease)
    resulting from:Resource allowance
    (3,259,987)
    (1,627,200)
    (1,211,828)Non-deductible Crown
    royalties, net of ARTC
    5,412,264
    1,313,089
    781,332Value of warrants expensed
    for book purposes
    114,772
    -
    -Interest component of trust
    distributions
    (722,894)
    -
    -Effect of change in tax
    pools
    (1,247,424)
    -
    -Effect of reduction in
    corporate tax rates
    (1,579,285)
    -
    -Non-taxable portion of
    capital gain
    -
    (1,310,552)
    -Capital taxes
    133,929
    132,000
    120,000Other
    339,148
    (130)
    13,099$2,075,228
    $1,043,000
    $682,000


> F-11

> 8. Income taxes (Continued)
>   The components of the net future income tax liability at December 31
>     were as follows:

2003
    2002Future income
    tax assets:Share issue
    costs
    $398,868
    $647,597Future
    abandonment and site restoration
    529,528
    295,321Deferred gain
    -
    75,015928,396
    1,017,933Future income
    tax liabilities:Property, plant
    and equipment
    13,083,004
    11,052,168Net future income tax liability
    $14,011,400
    $12,070,101




> At December 31, 2003 the Company had approximately $66.4 million (2002
>     - $62.6 million and 2001 - $43.2 million) of tax pools available to reduce future
>     taxable income.
>   9.    Unitholders Equity
>   (a) Authorized Trust Units
>     An unlimited number of Trust Units may be issued pursuant to the Trust
>     Indenture.

(b) Issued Trust Units

**Number of**
        **Units/Shares**
        **Amount**Balance, December 31, 2000
        9,190,278
        $5,031,846Issued upon exercise of options
        87,000
        99,450Issued pursuant to public offerings
        2,070,000
        7,081,024Issued on acquisition of property and
        equipment
        426,094
        1,300,000Issued on acquisition of Big Horn Resources
        Ltd. (note 3)
        6,992,872
        18,251,396Shares repurchased
        (465,000)
        (753,300)Issue costs incurred, net of income tax
        benefit of $1,118,251
        -
        (1,442,153)Balance,
        December 31, 2001
        18,301,244
        $29,568,263Issued upon exercise of options
        89,022
        171,127Shares repurchased
        (37,616)
        (74,315)Balance,
        December 31, 2002
        18,352,650
        $29,665,075Issued upon exercise of options
        and warrants
        2,598,906
        6,283,461Contributed surplus transferred on
        exercise of warrants
        -
        346,677Issued pursuant to Plan of
        Arrangement:Shares exchanged for Exchangeable shares and
        cancelled
        (2,000,000)
        (3,464,679)Shares exchanged for Trust Units and cancelled
        (18,951,556)
        (32,830,534)Trust Units issued
        18,951,556
        32,830,534Issued for Exchangeable Shares
        4,404
        7,629Balance, December 31, 2003
        18,955,960
        $32,838,163


> F-12

9.    Unitholders Equity (Continued)

> 

Pursuant to the Plan of Arrangement,
    18,951,556 Trust Units and 2,000,000 Exchangeable Shares were issued on November 25, 2003
    at a two for one exchange ratio and upon cancellation of all outstanding common shares of
    Enterra. The consideration attributed to the Trust Units and the Exchangeable Shares was
    the relative proportion of the carrying value of the common shares of Enterra prior to the
    exchange. Prior to December 31, 2003, 4,404 exchangeable shares were converted to Trust
    Units. The prior years number of shares issued in the share tables above have been
    restated to reflect the two for one exchange ratio under the Plan of Arrangement.



(c) Issued Exchangeable Shares

**Number of
        Units**
        **Amount**Issued pursuant to Plan of Arrangement
        2,000,000
        $3,464,679Exchanged for Trust Units
        (4,404)
        (7,629)Balance, December 31, 2003
        1,995,596
        $3,457,050


The Exchangeable Shares of the Company are
    convertible at any time into Trust Units (at the option of the holder) based on the
    exchange ratio. The exchange ratio is increased monthly based on the cash distribution
    paid on the Trust Units divided by the ten day weighted average unit price preceding the
    distribution payment date. During the period of November 25 to December 31, 2003, a total
    of 4,404 Exchangeable Shares were converted into 4,404 Trust Units at a one for one
    exchange ratio prevailing at the time. The exchange ratio at the time of issuance on
    November 25, 2003 and at December 31, 2003 was one Trust Unit for each Exchangeable Share.
    Cash distributions are not paid on the Exchangeable Shares. On the third anniversary of
    the issuance of the Exchangeable Shares, subject to extension of such date by the Board of
    Directors of the Trust, or at the Trusts option when the aggregate number of issued
    and outstanding Exchangeable Shares is less than 1,000,000, the Exchangeable Shares will
    be redeemed for Trust Units at a redemption price per exchangeable share equal to the
    value of that number of Trust Units equal to the exchange ratio as at that Redemption
    Date. The Exchangeable Shares of the Company are not listed for trading on an exchange.

(d) Contributed surplus

Balance at January 1, 2002
        $
                       
        -Value assigned to 100,000 warrants described
        in note 9(h)
        125,000Loss related to shares repurchased during year
        (59,971)Balance at
        December 31, 2002
        65,029Value assigned to 200,000 warrants described
        in note 9(h)
        281,648Transfer on exercise of warrants (note 9(b))
        (346,677)Balance at December 31, 2003
        $
                       
        -


> F-13

9.    Unitholders Equity (Continued)

> (e) Options
>     Enterra granted options to purchase common shares to directors,
>     officers, employees and consultants. Each option permitted the holder to purchase one
>     common share of Enterra at the stated exercise price. All options vest over 4 years and
>     are exercisable on a cumulative basis over 5 years. At the time of grant, the exercise
>     price is equal to the market price. The following options have been granted:

**Number of****Options**
    **Weighted-****average**
    **exercise**
    **price**Balance at December 31, 2000
    430,500
    $5.76Options granted
    990,000
    $4.41Options exercised
    (43,500)
    $2.29Options cancelled
    (577,000)
    $6.15Balance at
    December 31, 2001
    800,000
    $4.00Options granted
    232,000
    $5.30Options exercised
    (44,511)
    $3.84Options cancelled
    (115,786)
    $4.03Balance at
    December 31, 2002
    871,703
    $4.35Options granted
    31,500
    $15.74Options exercised
    (899,453)
    $4.74Options cancelled
    (3,750)
    $4.41Balance at December 31, 2003
    -
    -


> Of the 31,500 options granted during 2003, 6,000 were granted to
>     non-employees (2002  55,000). Compensation expense related to these options amounted
>     to $46,000 (2002 - $18,000) under the fair value based method of accounting. Total options
>     of 899,453 vested and were exercised at prices ranging from $4.00 to $18.58 pursuant to
>     the Plan of Arrangement.
>   (f) Estimated fair value of stock options
>     The estimated fair value of options was determined using the
>     Black-Scholes model under the following assumptions:

2003
    2002
    2001Weighted-average fair value of options granted
    ($/option)
    $ 7.75
    $2.83
    $0.76Risk-free interest rate (%)
    5.0
    5.0
    5.0Estimated hold period prior to exercise
    (years)
    5
    5
    5Expected
    volatility in the price of Enterras shares (%)
    50
    55
    30




> F-14

9.    Unitholders Equity
  (Continued)

> (g) Pro forma net income  fair value based method of accounting for options
>     The following shows pro forma net income and earnings per unit had the
>     fair-value based method of accounting been applied to options issued in 2003, 2002 and
>     2001:

**2003**
        2002
        2001Net earnings, as reported (in 000s)
        $ 5,004
        $ 4,977
        $ 1,617Less: Total stock-based employee compensation
        expense determined under fair value based method for all awards, net of related tax
        effects
        (631)
        (47)
        (27)Pro forma net earnings
        $ 4,373
        $ 4,930
        $ 1,590Earnings per Unit/ShareBasic as reported
        $ 0.26
        $ 0.27
        $ 0.12Basic pro forma
        $ 0.21
        $ 0.27
        $ 0.11Diluted as reported
        $ 0.26
        $ 0.26
        $ 0.12Diluted pro
        forma
        $ 0.21
        $ 0.26
        $ 0.11


> (h) Warrants

**Number of****Warrants**
        **Weighted****Average
        Price**Balance, December 31, 2000
        -
        -Issued pursuant to public offering
        1,000,000
        US$3.50Issued pursuant to underwriters agreement
        100,000
        US$5.40Balance,
        December 31, 2001
        1,100,000
        US$3.67Expired
        (1,000,000)
        US$3.50Issued pursuant to debt financing
        100,000
        US$2.60Balance,
        December 31, 2002
        200,000
        US$4.00Issued pursuant to debt financing agreement
        amendment
        200,000
        US$3.65Exercised pursuant to Plan of Arrangement
        (400,000)
        US$3.83Balance, December 31, 2003
        -
        -


> F-15

9.    Unitholders Equity (Continued)

> (h) Warrants (Continued)
>       On January 17, 2001, the Company completed a secondary public offering
>       in the United States. The offering consisted of 1,000,000 units of one common share and
>       one share purchase warrant for U.S. $4.55 per unit. The share purchase warrants were
>       exercisable at US$ 3.50 per share. They expired on May 17, 2002. The 100,000 share
>       purchase warrants related to the underwriters agreement were exercisable at U.S. $5.40 per
>       share starting January 16, 2002 and could be exercised for a four year period thereafter.
>       On March 28, 2002 the Company agreed to issue 300,000 share purchase warrants to an
>       arms length U.S.-based consulting firm in connection with a potential debt financing
>       in the United States. The warrants had a two-year term and were subject to different
>       exercise prices (100,000 warrants at US$2.60, 100,000 at US$3.30 and 100,000 at US$4.00).
>       The US$2.60 warrants vested upon the execution in May 2002 of a non-binding letter of
>       intent relating to the proposed financing. A value of $125,000 was assigned to the 100,000
>       warrants at US$2.60. This value was determined using the Black-Scholes Option Pricing
>       model using an interest rate of 5% and a volatility factor of 50%. The $125,000 was
>       credited to the Companys contributed surplus. The US$3.30 and US$4.00 warrants were
>       to vest only on the successful closing and funding of the proposed financing. At the May,
>       2003 shareholders meeting, the terms were amended to provide for immediate vesting of
>       these warrants as of the April 16, 2002 date of the agreement. The value of $281,648 was
>       expensed in the current year and included in note 9(d).
>     10.     Reconciliation of Earnings per Share Calculations
>     For the year ended December 31, 2003 the weighted average number of
>       units outstanding was 18,953,968. There are no options outstanding as at December 31, 2003
>       and therefore no dilution to earnings per unit for 2003. Prior years number of shares and
>       per share calculations have been restated to reflect the two for one exchange of units for
>       common shares under the Plan of Arrangement.
>       For the year ended December 31, 2002

**Net**
      **Earnings**
      **Weighted Average**
      **Shares Outstanding**
      **Per**
      **Share**Basic
      $4,977,401
      18,308,982
      $0.27Options and warrants assumed exercised
      
      1,607,998Shares assumed purchased
      
      (1,091,766)Diluted
      $4,977,401
      18,825,214
      $0.26


> Excluded from the above calculation are 61,000 options,
>       which were "out-of-the-money" in 2002.
>       For the year ended December 31, 2001

**Net**
      **Earnings**
      **Weighted Average**
      **Shares Outstanding**
      **Per**
      **Share**Basic
      $1,617,055
      13,984,786
      $0.12Options and warrants assumed exercised
      
      92,054Shares assumed purchased
      
      (81,826)Diluted
      $1,617,055
      13,995,014
      $0.12




> F-16

11.    Series 1 preferred shares

> On March 26, 2002 the Company purchased 6,123,870 of its Series 1
>     preferred shares for $2.3 million, resulting in a gain on redemption of $2,905,290. The
>     purchase was paid for with cash of $1,750,000 and a note payable of $550,000. This note
>     was repaid for $325,000 on August 15, 2002 resulting in an additional gain, net of legal
>     costs, of $206,181. During 2003, the remaining 749,047 shares were redeemed for $636,690
>     ($0.85 per share). A dividend of $33,428 (2002 - $22,549 ) was paid on the preferred
>     shares before their redemption. This amount is included in interest expense. At December
>     31, 2003 there were no Series 1 preferred shares outstanding ( 2002  749,047).

12.    Financial instruments

> The Trusts financial instruments recognized on the consolidated
>     balance sheets include accounts receivable, accounts payable and accrued liabilities,
>     distributions payable, income taxes payable, bank indebtedness and long-term debt. The
>     fair values of financial instruments other than bank debt approximates their carrying
>     amounts due to the short term nature of the instruments. The carrying value of bank
>     indebtedness approximates its fair value due to floating interest terms; the fair value of
>     the long-term debt approximates carrying value due to current rates for comparable terms
>     of long-term debt.
>     Due to the nature of its operation, the Trust is exposed to
>     fluctuations in commodity prices, foreign-currency exchange rates, interest rates and
>     credit risk. The Trust recognizes these risks and manages its operations to minimize the
>     exposure to the extent practical and, to a lesser extent, using derivative instruments.
>     The Trust uses non-exchange traded forwards, swaps and options, which may be settled in
>     cash or by delivery of the physical commodity. Management monitors the Trusts
>     exposure to the above risks and regularly reviews its derivative activities and all
>     outstanding positions.
>     (a) Commodity price risks
>         The Trusts most significant market risk exposure relates to crude
>         oil prices fluctuation. Crude oil prices and quality differentials are influenced by
>         worldwide factors such as OPEC actions, political events and supply and demand
>         fundamentals.
>         To a lesser extent the Trust is also exposed to natural gas price
>         movements. Natural gas prices are generally influenced by North American supply and
>         demand, and to a lesser extent local market conditions.
>         (b) Foreign currency exchange risk
>         The Trust is exposed to foreign currency fluctuations as crude oil and
>         natural gas prices received are referenced to U.S. dollar denominated prices.
>         (c) Credit risk
>         A substantial portion of the Trusts accounts receivable are with
>         customers and joint venture partners in the oil and gas industry and are subject to normal
>         industry credit risks. Purchasers of the Trusts natural gas, crude oil and natural
>         gas liquids are subject to an internal credit review to minimize the risk of non-payment.
>         (d) Interest rate risk
>         Interest rate risk exists principally with respect to the Trust's
>         indebtedness that bears interest at floating rates. At December 31, 2003, the Trust had
>         $33,959,733 of indebtedness bearing interest at floating rates and $4,168,548 of long-term
>         debt bearing interest at fixed rates.
>     F-17

13.    Hedging contracts

> Enterra entered into the following hedges to minimize its exposure to
>     fluctuations in commodity prices relating to its future sales of crude oil and gas. The
>     contracts are as follows:

> (a) Enterra entered into a physical zero cost collar arrangement during
>         2001 which provided a floor price of US$20 per barrel and a ceiling price of US$24 per
>         barrel for 500 barrels of oil per day. The contract was effective from November 1, 2001
>         through April 30, 2002.
>         (b) In July 2002, Enterra entered into a physical zero cost collar
>         arrangement with a floor price of US$22 per barrel and a ceiling price of US$28 per barrel
>         for 500 barrels of oil per day. The contract was effective from October 1, 2002 through
>         March 31, 2003.
>         (c) In July 2002, Enterra entered into two contracts to deliver natural
>         gas. One was for 1,500 mcf per day, priced at Cdn$4.60 per mcf. The other was for 1,500
>         mcf per day, priced at Cdn$4.45 per mcf. Both contracts were effective from November 1,
>         2002 through March 31, 2003
>         (d) In February of 2003 Enterra entered into several contracts to
>         deliver 2,000 barrels of oil per day for the period from April 1, 2003 to December 31,
>         2003. The prices and volumes are as follows:

**Volumes****(in
    barrels per day)**
    **Price****(in
    US dollars)**1,000
    US$29.60250
    US$29.71250
    US$29.50500
    US$29.80


> (e) In the third quarter of 2003, Enterra entered into contracts to
>         deliver 2,000 barrels of oil per day from January 1, 2004 to June 30, 2004, 500
>         barrels at US$26.68 to be delivered physically and 500 barrels at US$26.75 and 1,000
>         barrels at Cdn$38.50 to be delivered financially. At December 31, 2003 the contracts had
>         an estimated negative fair market value of $1,626,207.
>         (f) On January 23, 2004, the Trust entered into contracts to deliver
>         1,000 barrels of oil per day from July 1, 2004 to December 31, 2004 at Cdn$40.50.
>     Effective January 31, 2001, Enterra settled a fixed price contract
>     eliminating the requirement to deliver set physical quantities of oil at fixed prices.
>     Upon the cancellation of the contract Enterra received approximately $1,680,000, which was
>     recognized over the term of the contract. At December 31, 2003 the remaining deferred gain
>     related to this settlement was nil (2002 - $237,463).
>     
>     F-18
>   14.    Commitments
>   The Trust has commitments for the following payments over the next five
>     years:

**Thereafter****2004**
        **2005**
        **2006**
        **2007**
        **2008**Minimum capital lease
        payments
        $786,889
        $809,538
        $877,697
        $1,702,342
        $ -Imputed interest
        332,105
        260,530
        187,923
        96,873
        -Capital lease obligations
        1,118,994
        1,070,068
        1,065,620
        1,799,215
        -Rental payments re-office
        space
        460,447
        467,717
        414,770
        309,990
        640,920$1,579,441
        $1,537,785
        $1,480,390
        $2,109,205
        $640,920


During 2003 total rental expense was
    $299,312 (2002 - $240,555, 2001 - $167,545).



15.    Guarantees

> In the normal course of operations, the Trust may provide
>     indemnification in conjunction with certain transactions. The terms of these
>     indemnification obligations range in duration and often are not explicitly defined.  
>     In many cases, there is no maximum limit on these indemnification obligations and the
>     overall maximum amount of the obligation under such indemnification obligations cannot be
>     reasonably estimated. The Trust has not made significant payments under these and there
>     are no material indemnification obligations at year end.
>   16.    Subsequent events
>   (a) On January 16, 2004 the Trust entered into a financing
>         agreement whereby the Trust will issue 1,650,000 Trust Units at a price of US$10.00 per
>         unit for gross proceeds of US$16,500,000. Payment will be received pending registration of
>         the units.
>         (b) On January 30, 2004 the Trust closed an acquisition of petroleum
>         and natural gas properties in East Central Alberta for $19,847,000. At December 31,
>         2003, the Trust had made a refundable deposit on the property purchased in the amount of
>         $2,015,000. Results from operations will be included in the Trust from the closing date.
>         (c) On February 20, 2004 the Trust completed a private placement of
>         1,049,400 Trust Units at a price of US$11.25 per unit for gross proceeds of US$11,805,750
>         (US$10,265,463 net of financing costs).
>   17.    Differences between Generally Accepted Accounting Principles
>   in Canada and the United States of America
>   The Trusts consolidated financial statements have been prepared
>     in Canadian Dollars and in accordance with generally accepted accounting principles in
>     Canada ("Canadian GAAP"), which differ in some respects from those in the United
>     States of America ("U.S. GAAP"). Any differences in accounting principles as
>     they pertain to the accompanying consolidated financial statements were insignificant
>     except as described below:
>     F-19
>   17.    Differences between Generally Accepted Accounting
>   Principles in Canada and the United States of America (Continued)
>   (a) Property and equipment
>     The Trust performs a cost recovery ceiling test which limits net
>     capitalized costs to the undiscounted estimated future net revenue from proven oil and gas
>     reserves plus the cost of unproven properties less impairment, using year-end prices or
>     average prices in that year, if appropriate. In addition, the value is further limited by
>     including financing costs, administration expenses, future abandonment and site
>     restoration costs and income taxes. Under U.S. GAAP, companies using the "full
>     cost" method of accounting for oil and gas producing activities perform a ceiling
>     test using discounted estimated future net revenue from proven oil and gas reserves using
>     a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for this
>     reconciliation were those in effect at the applicable period end. Financing and
>     administration costs are excluded from the calculation under U.S. GAAP. At December 31,
>     2001 Enterra realized a U.S. GAAP ceiling test write-down of $28.7 million ($17.5 million
>     after tax). There was no such write-down at December 31, 2003 or December 31, 2002. As a
>     result of the 2001 write-down, the 2003 depletion expense under U.S. GAAP was lower by
>     $5.7 million ($3.4 million after tax and in 2002 $3.6 million ($2.1 million after tax).
>     (b) Financial instruments
>     FAS 133 requires the Trust to recognize all derivative instruments
>     (included derivative instruments embedded in other contracts) as defined,  in the
>     balance sheet as either an asset or a liability measured at fair value and requires that
>     changes in fair value be recognized currently in income unless specific hedge accounting
>     criteria are met. There are no similar standards in Canadian GAAP at this time. Changes in
>     the fair value of derivatives are recognized in earnings unless specific hedge criteria
>     are met. The negative fair value of such contracts at December 31, 2003 was $958,359 (2002
>     - $nil).
>     Hedge accounting treatment allows unrealized gains and losses to be
>     deferred in other comprehensive income (for the effective portion of the hedge) until such
>     time as the forecasted transaction occurs and requires that an entity formally document,
>     designate and assess effectiveness of derivative instruments that receive hedge accounting
>     treatment. Upon adoption, the Trust did not designate its hedging relationships. As a
>     result, the Trust is required to use fair value accounting for its derivative instruments
>     for U.S. GAAP and the change in fair value of these contracts has been reported in income.
>     The Trust routinely enters into commodity contracts to minimize its
>     exposure to fluctuations in commodity prices relating to its future sales of crude oil.
>     Such contracts often meet the criteria of FAS 133 as derivatives but are generally
>     eligible for the normal purchase and sale exception under FAS 138, "Accounting for
>     Certain Derivative Instruments and Certain Hedging Activities  An Amendment of FAS
>     133". Contracts that meet the criteria of this exception are not recognized on the
>     balance sheet as either an asset or a liability measured at fair value. The fair value of
>     such contracts at December 31, 2003 was $667,848 (2002 - $585,000).
>     At December 31, 2002, under Canadian GAAP, the Trust had a deferred
>     gain of $237,463 (2001 - $761,302) resulting from the settlement of a fixed price
>     contract, which is being amortized over the term of the contract. Under U.S. GAAP, this
>     gain, net of related income taxes, would be included in income as it did not qualify for
>     hedge accounting under FAS 133.
>     F-20
>   17.    Differences between Generally Accepted Accounting
>   Principles in Canada and the United States of America (Continued)
>   (c) Stock-based compensation
>     Under U.S. GAAP, FAS 123 establishes financial accounting and reporting
>     standards for stock-based employee compensation plans as well as transactions in which an
>     entity issues its equity instruments to acquire goods or services from non-employees.
>     During 2001, the Company granted 119,500 stock options to non-employees. The value
>     associated with these stock options was $90,924 for U.S. GAAP purposes. The fair value of
>     each option granted was estimated on the date of grant using the Black-Scholes
>     option-pricing model with the following assumptions: risk-free interest rate of 5%,
>     expected volatility of 30% and expected life of five years. After January 1, 2002, stock
>     options issued to non-employees resulted in the same accounting treatment under both
>     Canadian and U.S. GAAP.
>     The following table illustrates the effect on net income and earnings per unit if the
>     Trust had applied the fair value recognition provisions of FAS 123 to stock-based employee
>     compensation.

2003
    2002
    2001Net earnings, as reported (in 000s)
    $ 6,510
    $ 6,748
    $ (15,534)Less: Total stock-based employee compensation
    expense determined under fair value based method for all awards net of related tax effects
    (737)
    (110)
    (55)Pro forma net earnings
    $ (5,773)
    $ 6,638
    $ (15,589)Earnings per unitBasic - as reported
    $ 0.34
    $ 0.37
    $ (1.11)Basic - pro forma
    $ 0.30
    $ 0.36
    $ (1.11)Diluted - as reported
    $0.34
    $ 0.36
    $ (1.11)Diluted -
    pro forma
    $ 0.30
    $ 0.35
    $ (1.11)


> (d) Cash flows
>     Future abandonment and site restoration costs are presented as
>     investing activities but under FAS 143 they would be classified as operating activity and
>     included in the reconciliation of beginning and ending asset retirement obligations.
>     (e) Earnings
>     Interest and amortization of deferred financing charges would be
>     presented in the non-operating section of the statement of earnings under U.S. GAAP while
>     restructuring charges would be presented in the operating section of the statement of
>     earnings for all periods presented.
>     
>     
>     F-21
>   17.    Differences between Generally Accepted Accounting Principles
>   in Canada and the United States of America (Continued)
>   (f) Comprehensive Income
>   There are no items that would be part of Comprehensive Income other than net income.

> (g) Asset Retirement Obligations
>     For Canadian reporting purposes, the Trust provides for site
>     restoration abandonment on a unit of production basis over the life of the Trusts
>     proven reserves. Changes to Canadian accounting standards, effective January 1, 2004, are
>     expected to eliminate this GAAP difference in future years. Under US GAAP the provision
>     for future abandonment and site restoration costs of $1.5 million (2002 - $0.9 million) is
>     a reduction of property and equipment.
>     Effective January 1, 2003 the Trust adopted Financial Accounting
>     Standards Board (FASB) Statement No. 143, Accounting for Asset Retirement Obligations
>     (FAS 143) for US GAAP reporting purposes. FAS 143 requires recognition of a liability for
>     the future retirement obligations associated with property, plant and equipment, which
>     includes oil and gas wells and facilities. These obligations, which generally relate to
>     dismantlement and site restoration, are initially measured at fair value, which is the
>     discounted future value of the liability. This fair value is capitalized as part of the
>     cost of the related asset and amortized to expense over its useful life. The liability
>     accretes until the Trust expects to settle the retirement obligation.
>     Had FAS 143 been applied during all periods presented, the results
>     would have been reported as follows:

January, 2002
    $1,913,161December 31, 2002
    $3,090,389December 31,
    2003
    $2,188,052


> The change in the asset retirement obligation since the beginning of
>     the year is as follows:

2003Asset Retirement Obligation at January 1
    $3,090,389Obligation incurred
    744,422Abandonment expenditures
    (5,414)Property disposition
    (1,753,446)Accretion
    112,101Revision in estimate
    -Effect of foreign exchange
    -Asset Retirement Obligation at December 31
    $2,188,052


> F-22
>   17.     Differences between
>   Generally Accepted Accounting Principles in Canada and the United States of America
>   (Continued)
>   (g) Asset Retirement Obligations (Continued)
>     This change in accounting policy has been reported as a cumulative
>         effect adjustment in the Consolidated Statement of Earnings as a loss of $1,148,165, net
>         of income taxes of $607,976. Under the former US GAAP accounting rules, the Trusts
>         results would have been as follows:

**2002**
        **2001**Net earnings - US GAAPAs reported
        $6,748,492
        $(15,534,391)Cumulative effect of change in accounting principleDepreciation, depletion, amortization and accretion, net
        (202,284)
        (215,936)Adjusted
        $6,546,208
        $(15,750,327)Earnings per unit/shareBasic as reported
        $0.37
        ($1.11)Adjusted
        $0.36
        ($1.13)Diluted as reported
        $0.36
        ($1.11)Adjusted
        $0.35
        ($1.13)


> (h) Balance sheets
>         The adjustments using U.S. GAAP would result in the following changes
>         to the consolidated balance sheets of the Trust:

2003
        2002Canadian
        U.S.
        Canadian
        U.S.GAAP
        GAAP
        GAAP
        GAAPAssetsCurrent assets
        $11,285,060
        $11,285,060
        $8,078,752
        $8,078,752Capital assets (a)(g)
        104,821,285
        84,288,022
        94,354,313
        68,307,526Deferred financing charges
        123,208
        123,208
        284,040
        284,040$116,229,553
        $95,696,290
        $102,717,105
        $76,670,318LiabilitiesCurrent liabilities
        $49,522,455
        $49,522,455
        $46,061,986
        $46,061,986Long-term debt
        3,385,618
        3,385,618
        4,112,681
        4,112,681Financial derivative liabilities (b)
        -
        958,359
        -
        -Future income taxes (a) (b) (c)
        14,011,400
        5,644,691
        12,070,101
        2,485,695Asset retirement obligation provision (g)
        1,529,244
        2,188,052
        934,857
        -Deferred gain (b)
        -
        -
        237,463
        -Series 1 preferred shares
        -
        -
        636,690
        636,69068,448,717
        61,699,175
        64,053,778
        53,297,052


> F-23

17.    Differences between Generally Accepted
    Accounting Principles in Canada and the United States of America (Continued)

> (h) Balance sheets (Continued)
>       2003
>           2002Canadian
>           U.S.
>           Canadian
>           U.S.GAAP
>           GAAP
>           GAAP
>           GAAPUnitholders equityUnitholders capitalAuthorized 
>           unlimited number of Trust Units (2002  unlimited number of common shares)
>           Issued - 2003 -18,955,960 units
>           - 2002 - 18,352,650
>           shares
>           32,838,163
>           32,928,457
>           29,665,075
>           29,665,075Exchangeable shares  1,995,596
>           3,457,050
>           3,457,050
>           -
>           -Contributed surplus
>           -
>           -
>           65,029
>           155,323Accumulated earnings (deficit)
>           13,937,025
>           63,010
>           8,933,223
>           (6,447,132)Accumulated distributions
>           (2,451,402)
>           (2,451,402)
>           -
>           -$47,780,836
>           $33,997,115
>           $38,663,327
>           23,373,266$116,229,553
>           $95,696,290
>           $102,717,105
>           $76,670,318F-24

17.    Differences between Generally Accepted Accounting Principles in
    Canada and the United States of America (Continued)

> (i) Income statements:
>       The adjustments using U.S. GAAP would result in the following changes
>       to the consolidated financial statements of the Trust:

2003
      2002
      2001Net earnings (loss) under Canadian GAAP
      $5,003,802
      $4,977,401
      $1,617,055Adjustments:Full cost accounting (a)
      -
      -
      (28,695,705)Related income taxes
      -
      -
      11,159,101Hedging gain (b)
      (237,463)
      (523,839)
      761,302Related income taxes
      96,766
      220,641
      (324,315)Depletion expense (a)
      5,676,000
      3,583,775
      -Related income taxes
      (2,312,970)
      (1,509,486)
      -Stock-based compensation (c)
      -
      -
      (90,294)Unrealized loss on financial instruments (b)
      (958,359)
      -
      -Related income taxes
      390,531
      -
      38,465Net earnings (loss) before undernoted items
      under U.S. GAAP
      7,658,307
      6,748,492
      (15,534,391)Cummulative effect of change in accounting
      principle  FAS #143
      (1,756,141)
      -
      -Related income taxes
      607,976
      -
      -Net earnings (loss) under U.S. GAAP
      $6,510,142
      $6,748,492
      ($15,534,391)Net earnings (loss) per unit/share before
      under noted items under US GAAP:Basic
      $0.40
      $0.37
      ($1.11)Diluted
      $0.40
      $0.36
      ($1.11)Net earnings (loss) per unit/share relating to
      change in accounting principle:Basic
      ($0.06)
      $ -
      $ -Diluted
      ($0.06)
      $ -
      $ -Net earnings (loss) per unit/share under US
      GAAP:Basic
      $0.34
      $0.37
      ($1.11)Diluted
      $0.34
      $0.36
      ($1.11)


> 

F-25

17.    Differences between Generally Accepted Accounting
    Principles in Canada and the United States of America (Continued)

> (j) Reconciliation of Earnings per Share Calculations
>       For the year ended December 31, 2003 the weighted average number of
>       units outstanding was 18,953,968. There are no options outstanding as at December 31, 2003
>       and therefore no dilution to earnings per unit for 2003.

**For the year ended December 31, 2002****Net****Earnings**
      **Weighted Average****Shares Outstanding**
      **Per****Share**Basic
      $6,748,492
      18,308,982
      $0.37Options and warrants assumed exercised
      
      1,607,998Shares assumed purchased
      
      (1,091,766)Diluted
      $6,748,492
      18,825,214
      $0.36




**For the year ended December 31, 2001****Net****Earnings**
      **Weighted Average****Shares
      Outstanding**
      PerShareBasic
      $(15,534,391)
      13,984,786
      $(1.11)Options and warrants assumed exercised
      
      92,054Shares assumed purchased
      
      (81,826)Diluted
      $(15,534,391)
      13,995,014
      $(1.11)




New Accounting Pronouncements

> The following standards issued by the FASB do not impact us at this time:
>       (a) Interpretation No. 46, "Consolidation of Variable Interest
>           Entities", effective for the Trust for the period ending December 31, 2004.
>           (b) FAS No. 150, "Accounting for Certain Financial Instruments
>           with Characteristics of both Liabilities and Equity", effective for financial
>           statements issued after June 15, 2003.
>           (c) FAS No. 132 (revised 2003), "Employers Disclosures about
>           Pensions and Other Post Retirements Benefits - an amendment of SFAS No. 87, 88 and
>           106", effective for financial statements issued after December 15, 2003.
>           (d) FAS No. 149, "Amendment of Statement 133 on Derivative
>           Instruments and Hedging Activities", effective for contracts entered into or modified
>           after June 30, 2003.
>         The Trust will continue to assess the applicability of these standards in the future.
>       F-26

Supplemental disclosure about Oil and Gas producing activities (unaudited)

> The following oil and gas information is provided in accordance with
>       the US Financial Accounting Standards Board Statement No. 69 "Disclosure About Oil
>       and Gas Producing Activities". The Trust follows the full cost method of accounting.
>       (a) Capitalized Costs
>       The aggregate amounts of costs capitalized for gas and oil producing
>       activities, and related aggregate amounts of accumulated depreciation, depletion and
>       amortization, at December 31, 2003 and 2002 follow:

2003
      2002Capitalized costsProved properties being amortized
      $112,219,344
      $80,137,875Unproved properties not being amortized
      5,037,355
      3,966,828Total
      capitalized costs
      117,256,699
      84,104,703Less accumulated depletion, depreciation,
      future site restoration and amortization
      (32,968,677)
      (15,797,177)Net capitalized costs
      $84,288,022
      $68,307,526


> The following costs were incurred in oil and gas producing activities
>       during the years ended December 31, 2003, 2002 and 2001:

2003
      2002
      2001Property acquisition costsProved properties
      $
                    -
      $512,338
      $47,010,438Unproved properties
      8,028,090
      3,643,053
      3,182,644Exploration costs
      765,505
      167,947
      442,028Development costs
      42,503,250
      31,557,918
      11,781,390Total costs incurred
      $51,296,845
      $35,881,256
      $62,416,500








> F-27

Supplemental disclosure about Oil and Gas producing activities
  (unaudited) (Continued)

> (b) Reserves Quantity Information
>       Estimated net quantities of proved gas and oil (including condensate)
>       reserves in Canada at December 31, 2003, 2002 and 2001, and changes in the reserves during
>       those years, are shown in the two tables which follow.

2003
      2002
      2001Proved developed and undeveloped reserves
       Oil (mboe)At January 1
      5,234.2
      4,126.9
      2,330.9Changes in reserves:Extensions, discoveries and other additions
      2,266.6
      2,564.3
      730.0Revisions of previous estimates
      (457.9)
      (60.8)
      4.9Production
      (1,406.2)
      (533.0)
      (582.2)Purchases of oil in place
      113.4
      -
      1,698.4Sales of oil in place
      (600.8)
      (863.2)
      (55.1)At December 31
      5,149.3
      5,234.2
      4,126.9Proved developed reserves - Oil (mboe)At January 1
      3,951.7
      3,733.8
      2,048.5At December
      31
      5,149.3
      3,951.7
      3,733.8




2003
      2002
      2001Proved developed and undeveloped reserves
       Gas (mboe)At January 1
      2,174.4
      1,794.0
      162.7Changes in reservesExtensions, discoveries and other additions
      534.0
      938.5
      494.8Revisions of previous estimates
      (183.0)
      (175.7)
      (270.7)Production
      (427.0)
      (313.7)
      (113.3)Purchases of gas in place
      26.1
      -
      1,578.6Sales of gas in place
      (1,106.4)
      (68.7)
      (58.1)At December 31
      1,018.1
      2,174.4
      1,794.0Proved developed reserves - Gas (mboe)At January 1
      2,037.5
      1,650.2
      162.7At December
      31
      1,018.1
      2,037.5
      1,650.2


> F-28

Supplemental disclosure about Oil and Gas producing activities
  (unaudited) (Continued)

> (c) Standardized Measure of Discounted Future Net Cash Flows and
>       Changes Therein
>       The following tabulation has been prepared in accordance with the FASBs rules for
>       disclosure of a standardized measure of discounted future net cash flows relating to
>       proved gas and oil reserve quantities owned by the Trust.

2003
      2002
      2001Future cash inflows (000s)
      $207,948
      $309,953
      $186,597Less:Future development costs (1)
      (200)
      (7,487)
      (4,802)Future production costs
      (83,332)
      (109,383)
      (83,314)Future income tax expense
      (15,174)
      (54,959)
      (23,550)Future cash
      flows
      109,242
      138,124
      74,931Less annual discount (10% a year)
      (18,683)
      (31,453)
      (22,554)Standardized measure of discounted future net cash flows
      $90,559
      $106,671
      $52,377


> (1) Amounts exclude the effect of derivative instruments
>         designated as hedges of future sales of production at year end.
>       In the foregoing determination of future cash inflows, sales prices for
>       gas and oil were based on contractual arrangements or market prices at year-end. Future
>       costs of developing and producing the proved gas and oil reserves reported at the end of
>       each year shown were based on costs determined at each such year end, assuming the
>       continuation of existing economic conditions. Future income taxes were computed by
>       applying the appropriate year-end or future statutory tax rate to future pretax net cash
>       flows, less the tax basis of the properties involved, and giving effect to tax deductions,
>       permanent differences and tax credits.
>       It is not intended that the FASBs standardized measure of
>       discounted future net cash flows represent the fair market value of the Trusts
>       proved reserves. The Trust cautions that the disclosures shown are based on estimates of
>       proved reserve quantities and future production schedules which are inherently imprecise
>       and subject to revision, and the 10 percent discount rate is arbitrary. In addition, costs
>       and prices as of the measurement date are used in the determinations, and no value may be
>       assigned to probable or possible reserves.
>       F-29

Supplemental disclosure about Oil and Gas
  producing activities (unaudited) (Continued)

> The following tabulation is a summary of changes between the total
>       standardized measure of discounted future net cash flows at the beginning and end of each
>       year.

2003
      2002
      2001Standardized measure of discounted
      future net cash flows at January 1
      $106,671
      $52,377
      $22,670Changes in the year resulting from:Sales and transfers of oil and gas produced during the year, net of
        production costs
      (41,679)
      (15,525)
      (11,252)Net change in sales and transfer prices, net of production costs
      (45,194)
      21,167
      (3,791)Extensions, discoveries and other additions, net of future production
        and development cost
      46,433
      69,718
      14,183Change in estimated future development costs
      9
      (209)
      (30)Development costs incurred during the period that reduced future
        development costs
      7,486
      3,251
      2,291Revisions of previous quantity estimates
      (8,106)
      (2,801)
      (2,279)Accretion of discount
      10,667
      5,238
      4,075Net change in income taxes
      30,391
      (25,983)
      (8,498)Purchases of proved reserves in place
      -
      -
      40,000Sales of proved reserves in place
      (18,263)
      (5,810)
      (1,710)Change in production rates (timing) and other
      2,144
      5,248
      (3,282)Standardized measure of discounted future net cash flows at
      December 31
      $90,559
      $106,671
      $52,377


> 

F-30