Important Links

News Releases

Press Release Navigation
<<< Previous Headlines Next >>>
Harvest Energy Trust Announces Year End 2003 Audited Financial Results and Reserves

Apr 16, 2004 - 12:12 ET

CALGARY, ALBERTA--(CCNMatthews - Apr 16, 2004) - (TSX: HTE.UN) - 
Harvest Energy Trust (the "Trust" or "Harvest") announced today 
its 2003 audited financial and operating results and a summary of 
its independent engineering evaluation, effective January 1, 
2004, completed by McDaniel & Associates Consultants Ltd. 
("McDaniel"). The evaluation of the oil and natural gas reserves 
was prepared in accordance with National Instrument 51-101 ("NI 
51-101"). 


/T/

FINANCIAL(1) & OPERATIONAL HIGHLIGHTS

-----------------------------------------------------------------------
                                 Three Months         Year       Period
Financial                               Ended        Ended        Ended
($000's, except per trust             Dec. 31,     Dec. 31,     Dec. 31,
 unit and per BOE(2))                    2003         2003      2002 (3)
-----------------------------------------------------------------------

Oil and natural gas sales              39,825      119,351       22,709

Net Income                              6,043       16,710        5,136
 Per trust unit, basic(6)                0.37         1.33         3.69
 Per trust unit, diluted(6)              0.36         1.29         3.46
 Per BOE                                 4.42         4.15         6.81

Cash flow from operations(4)           13,692       46,487        9,504
 Per trust unit, basic (non GAAP)(6)     0.85         3.69         6.83
 Per trust unit, diluted (non GAAP)(6)   0.82         3.58         6.43
 Per BOE                                10.02        11.54        12.61

Cash distributions declared            10,210       30,685        1,863
 Cash distributions declared
  per unit                               0.60         2.40         0.20

Payout ratio(5)                            75%          66%          20%

Debt, net of working capital           53,555       53,555       34,563

Capital expenditures:
 Exploitation, development
  and other                             5,096       26,623          770
 Acquisitions                          79,500      108,677       76,153

Weighted average trust units
 outstanding (000's)(6)
  Basic                                16,175       12,591        1,392
  Diluted                              16,668       13,003        1,479
-----------------------------------------------------------------------

(1) All financial figures should be read in conjunction with the 
    attached audited consolidated financial statements and accompanying
    notes and the Management's Discussion and Analysis for the year
    ended December 31, 2003.

(2) Unit Equivalency: Natural gas is converted to an oil equivalent
    basis utilizing a 6 mcf:1 bbl conversion ratio. BOE's may be
    misleading, if used in isolation. A BOE conversion ratio of 6 mcf:1
    bbl is based on an energy conversion method primarily applicable at
    the burner tip and does not represent a value equivalency at the
    wellhead.

(3) From the date of formation on July 10, 2002 to December 31, 2002.

(4) Represents cash provided by operating activities before change in
    non-cash working capital.

(5) Cash distributions declared divided by cash flow from operations.

(6) On December 5, 2002, the Trust became a public entity listed on the
    Toronto Stock Exchange, at which time 9,312,500 trust units were
    issued. Thus these trust units were outstanding for only 27 days in
    2002, and thus net income per trust unit and cash flow from 
    operations per trust unit for the period ended December 31, 2002 
    reflect a low weighted average of trust units outstanding.

-----------------------------------------------------------------------
                                 Three Months         Year       Period
                                        Ended        Ended        Ended
                                      Dec. 31,     Dec. 31,     Dec. 31,
Operating                                2003         2003         2002
-----------------------------------------------------------------------

Production
 Light and medium crude oil (bbl/d)     8,741        5,314        2,718
 Heavy crude oil (bbl/d)                5,756        5,444        1,463
 Natural gas liquids (bbl/d)               70           64           22
 Natural gas (mcf/d)                    1,744        1,311          624
-----------------------------------------------------------------------

Total (BOE/d)                          14,858       11,040        4,307

Product prices:
 Light and medium oil ($/bbl)           32.66        32.83        34.21
 Heavy oil ($/bbl)                      24.92        27.34        22.63
 Natural gas liquids ($/bbl)            29.18        29.92        37.64
 Natural gas ($/mcf)                     6.01         6.70         4.54
-----------------------------------------------------------------------

Oil equivalent ($/BOE)                  29.13        29.62        30.13

Operating expenses ($/BOE)               9.50         8.94         8.49
-----------------------------------------------------------------------

-----------------------------------------------------------------------
                                 Three Months         Year       Period
Trading Statistics                      Ended        Ended        Ended
($ per trust unit,                    Dec. 31,     Dec. 31,     Dec. 31,
 except volume)                          2003         2003      2002 (1)
-----------------------------------------------------------------------

High                                    14.20        14.20         9.50
Low                                     11.97         9.45         8.25
Close                                   14.07        14.07         9.50

Volume traded                       2,925,275    7,496,032      561,757
-----------------------------------------------------------------------

(1) On December 5, 2002, the trust units began trading on the Toronto
    Stock Exchange.

/T/

MESSAGE TO UNITHOLDERS 

The year ended December 31, 2003 was Harvest's first complete 
year of operations. Harvest's business plan has remained constant 
since its formation in July 2002, and has proved to be successful 
in the past year in achieving its fundamental objectives of 
providing Unitholders with stable and reliable distributions 
while sustaining asset value per unit. This plan employs a 
strategy of focusing on a hands-on approach to acquiring, 
developing and operating high quality, mature oil and natural gas 
properties in the Western Canadian sedimentary basin. Harvest's 
current production consists of primarily oil producing properties 
located in the Provost region of East Central Alberta and the 
Carlyle region of Southeastern Saskatchewan. During the first 
full year of operations Harvest achieved strong financial and 
operating results. Harvest doubled production through 
acquisitions, most significantly acquiring the Carlyle properties 
in Southeastern Saskatchewan, and an active optimization and 
development program. Performance at operated properties exceeded 
internal targets for production and reserve replacement. These 
successes supported our primary goal of delivering to Unitholders 
monthly distributions of $0.20 per unit throughout 2003, while 
enabling Harvest to retain approximately 30% of cash flow for 
reinvestment. Our capital expenditure and acquisition program 
supported a successful year of asset renewal, with strong reserve 
replacement performance. 

2003 Highlights 

- Harvest maintained a stable monthly distribution payment of 
$0.20 per trust unit per month throughout 2003 for a total of 
$2.40 per trust unit in distributions for the year; 

- Capital investment totaled $135.3 million in 2003, of which 
$108.7 million was for acquisitions of producing properties. The 
remainder was used to fund our capital program including 21 wells 
drilled with a 100% success ratio; 

- Harvest acquired high quality producing oil properties at 
Carlyle in Southeastern Saskatchewan in October 2003 for $80 
million, adding production of 5,100 BOE per day; 

- The December 2003 exit rate production was approximately 15,400 
BOE per day resulting in an 80% increase from December 2002; 

- Year-end independent engineering evaluation provided positive 
reserve appreciation, an increase in working interest reserves 
before the deduction of royalties of 139% on a proved plus 
probable basis and a replacement of production of 577% on a gross 
working interest basis before deduction of royalties.  Finding, 
development and acquisition costs amounted to $6.75 per BOE, on a 
proved plus probable basis; 

- Harvest exited 2003 with net debt (demand loan plus working 
capital) to annualized fourth quarter cash flow of 1.0:1. 

Hedging 

Harvest has developed a risk management policy that uses 
commodity hedges to mitigate commodity price risk, particularly 
as it relates to oil sales. The objective of Harvest's risk 
management policy is to provide Unitholders with greater 
distribution stability and certainty. Note 12 to the attached 
Consolidated Financial Statements describes Harvest's commodity 
contracts as at December 31, 2003. 

Taxability 

Cash distributions are comprised of a return of capital portion 
(tax deferred) and a return on capital portion (taxable). For 
cash distributions received by a Canadian resident, outside of a 
registered pension or retirement plan the distribution declared 
in December 2002 and paid in January 2003 was deemed to be 100% 
tax deferred. For the distributions declared in 2003 and paid in 
the months of February 2003 through to January 2004, 41% of the 
distributions were taxable and 59% were tax deferred. 

RESERVES 

Reserve estimates have been calculated in compliance with the 
newly implemented NI 51-101. These new standards establish a 
higher mandated confidence level for both proven and probable 
reserve determination. Under NI 51-101, proven reserves are 
defined as reserves that can be estimated with a high degree of 
certainty to be recoverable with a target of a 90% probability 
that the actual reserves recovered over time will equal or exceed 
proven reserve estimates, while probable reserves are defined as 
having an equal (50%) probability that the actual reserves 
recovered will equal or exceed the proven plus probable reserve 
estimates. In accordance with NI 51-101, proven undeveloped 
reserves have been recognized in cases where plans are in place 
to bring the reserves on production within a short, well defined 
time frame. Proven undeveloped reserves often involve infill 
drilling into existing pools. 

Reserve Highlights 

- Total proved plus probable reserves increased 139% from the 
prior year to 33.0 million BOE, prior to accounting for 
production on a gross working interest basis before deduction of 
royalties. Accounting for 2003 production (4.029 MBOE), total 
proved plus probable reserves increased by 168%; 

- Over 577% of 2003 production was replaced through reserve 
additions on a gross working interest basis before deduction of 
royalties; 

- Proved plus probable reserve life index (RLI) increased 40%, 
from 4.5 years to 6.3 years; 

- Proven plus probable finding, development and acquisition costs 
for 2003 were $6.75 per BOE; 

- The cost of acquiring proven plus probable reserves was $5.32 
per BOE on a gross basis before deduction of royalties. 

Additional reserve disclosure tables, as required under NI 
51-101, will be contained in the Annual Information Form that 
will be filed on SEDAR. The reserve estimates contained in the 
following table are working interest reserves before the 
deduction of royalties. 


/T/

-----------------------------------------------------------------------
Reserves Summary                    Crude             Natural
January 1, 2004 -                     Oil      NGLs       Gas     Total
 McDaniel Jan. 1/04 Pricing         (Mbbl)    (Mbbl)    (Mmcf)    (MBOE)
-----------------------------------------------------------------------
Proved Producing                   25,437       115     1,910    25,870
Total Proved                       26,763       122     1,988    27,216
Probable                            5,670        32       711     5,821
                                 --------------------------------------
Total Proved plus Probable         32,433       154     2,699    33,037
                                 --------------------------------------

Established Reserves: Equivalent
 to 2004 Proved + Probable
 January 1, 2003                   13,387        90     2,108    13,829
                                 --------------------------------------
% Increase                            142%       71%       28%      139%
-----------------------------------------------------------------------

2004 OUTLOOK

- Based on current operations Harvest provides the following guidance
  for 2004:

-----------------------------------------------------------------------
                                                    Guidance    Results
                                                        2004       2003
-----------------------------------------------------------------------

Daily production (BOE/d)                     15,000 - 15,500     11,040
Average Royalty Rate                                15% - 17%      13.8%
Operating expense ($/BOE)                    $10.00 - $10.50      $8.94
-----------------------------------------------------------------------

ADVISORY: Certain information regarding Harvest Energy Trust and
Harvest Operations Corp. including management's assessment of future
plans and operations, may constitute forward-looking statements under
applicable securities law and necessarily involve risks associated
with oil and natural gas exploration, production, marketing and
transportation such as loss of market, volatility of prices, currency
fluctuations, imprecision of reserve estimates, environmental risks,
competition from other producers and ability to access sufficient
capital from internal and external sources. As a consequence, actual
results may differ materially from those anticipated in the
forward-looking statements.

For further information please contact:

Jacob Roorda
President 
Telephone: (403) 265-1178

or

David M. Fisher
Vice President, Finance 
Telephone: (403) 265-1178
Facsimile: (403) 265-3490
Email: information@harvestenergy.ca
Website: www.harvestenergy.ca


Harvest Energy Trust
Consolidated Balance Sheets (Audited)


-----------------------------------------------------------------------
                                          December 31,      December 31,
                                                 2003              2002
-----------------------------------------------------------------------
Assets

Current assets
 Cash and short-term investments        $           -     $   4,502,947
 Accounts receivable                       19,167,646        13,577,870
 Prepaid expenses and deposits             12,130,895           534,573
-----------------------------------------------------------------------
                                           31,298,541        18,615,390

Deferred financing charges, net
 of amortization                            1,988,728         2,209,792
Future income tax (Note 11)                11,585,000         1,272,000

Property, plant and equipment
 (Notes 4 and 5)                          175,377,231        71,631,507
-----------------------------------------------------------------------

                                        $ 220,249,500     $  93,728,689
-----------------------------------------------------------------------
-----------------------------------------------------------------------


Liabilities and Unitholders' Equity

Current liabilities
 Accounts payable and accrued
  liabilities                           $  17,186,335     $   5,640,176
 Cash distributions payable                 3,421,801         1,862,500
 Accrued interest payable                     231,507           389,349
 Equity bridge interest payable
  (Notes 10 and 14)                           665,069                 -
 Demand loan (Note 6)                      63,348,972        45,286,396
-----------------------------------------------------------------------
                                           84,853,684        53,178,421

Site restoration provision (Note 7)         4,321,558           544,178
-----------------------------------------------------------------------
                                           89,175,242        53,722,599

Unitholders' equity
 Unitholders' capital (Note 8)            117,406,737        36,727,997
 Equity bridge notes (Note 10)             25,000,000                 -
 Accumulated income                        20,975,821         5,136,093
 Contributed surplus                          239,063             4,500
 Accumulated cash distributions           (32,547,363)       (1,862,500)
-----------------------------------------------------------------------
                                          131,074,258        40,006,090
-----------------------------------------------------------------------
                                        $ 220,249,500     $  93,728,689
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Subsequent events (Note 15)
Commitments and contingencies (Note 16)
See accompanying notes to consolidated financial statements.




Harvest Energy Trust
Consolidated Statement of Income and Accumulated Income (Audited)

-----------------------------------------------------------------------
                                                            Period from
                                                       July 10 (date of
                                           Year ended         formation)
                                          December 31,   to December 31,
                                                 2003              2002
-----------------------------------------------------------------------
Revenue
 Oil and natural gas sales              $ 119,351,486     $  22,708,921
 Hedging loss                             (18,924,364)       (1,009,060)
 Royalty income                               660,452           119,982
 Royalty expense                          (17,072,534)       (2,864,411)
-----------------------------------------------------------------------
                                           84,015,040        18,955,432
Expenses
 Operating                                 36,044,629         6,396,294
 General and administrative                 4,339,738           576,780
 Interest                                   2,975,236         2,010,032
 Finance charges and amortization
  of deferred finance charges               2,607,240           635,511
 Site restoration and reclamation           4,354,620           544,178
 Depletion, depreciation and
  amortization                             29,361,741         5,136,829
 Foreign recovery gain                     (4,373,510)         (255,056)
-----------------------------------------------------------------------
                                           75,309,694        15,044,568

-----------------------------------------------------------------------
Income before taxes                         8,705,346         3,910,864

Taxes
 Large corporation tax                        157,382            46,771
 Future tax recovery (Note 11)             (8,162,038)       (1,272,000)
-----------------------------------------------------------------------

Net income for the period                  16,710,002         5,136,093
-----------------------------------------------------------------------

Interest on equity bridge notes
 (Note 10)                                   (870,274)                -

Accumulated income, beginning of
 period                                     5,136,093                 -

Accumulated income, end of period       $  20,975,821     $   5,136,093
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Net income per trust unit (Note 9)
 Basic                                  $        1.33     $        3.69
 Diluted                                $        1.29     $        3.46
-----------------------------------------------------------------------

See accompanying notes to consolidated financial statements.



Harvest Energy Trust
Consolidated Statement of Cash Flows (Audited)

-----------------------------------------------------------------------
                                                            Period from
                                                       July 10 (date of
                                           Year ended         formation)
                                          December 31,   to December 31,
                                                 2003              2002
-----------------------------------------------------------------------

Cash provided by (used in)
Operating Activities
 Net income for the period               $ 16,710,002       $ 5,136,093
 Items not requiring cash
  Site restoration and reclamation          4,354,620           544,178
  Depletion, depreciation and
   amortization                            29,361,741         5,136,829
  Foreign exchange (gain) loss              1,432,074          (255,056)
  Amortization of finance charges           2,555,769           209,788
  Future tax expense                       (8,162,038)       (1,272,000)
  Unit based compensation                     234,563             4,500
-----------------------------------------------------------------------
Cash flow from operations                  46,486,731         9,504,332
Change in non-cash working
 capital (Note 13)                        (12,285,485)       (6,974,243)
-----------------------------------------------------------------------
                                           34,201,246         2,530,089
Financing Activities
 Issue of trust units, net of costs        61,691,083        31,727,997
 Issue of trust units under the
  distribution reinvestment plan,
  net of costs (Note 8)                    10,637,657                 -
 Issue of equity bridge notes
  (Note 10 and 14)                         33,500,000                 -
 Repayment of equity bridge notes
  (Note 10 and 14)                         (8,500,000)                -
 Issue of bridge notes (Note 14)           25,000,000                 -
 Repayment of bridge notes
  (Note 14)                               (25,000,000)                -
 Interest on equity bridge notes             (205,205)                -
 Initial financing                                  -        55,041,491
 Repayment of initial financing                     -       (55,041,491)
 Issuance of debentures                             -         5,000,000
 Increase in demand loan                  143,660,601        60,202,789
 Repayment of demand loan                (128,397,535)      (14,661,337)
 Repayment of promissory note
  payable                                    (850,000)                -
 Financing costs                           (2,334,705)       (2,419,580)
 Cash distributions                       (29,125,562)                -
 Change in non-cash working
  capital balances related
  to financing activities (Note 13)         2,224,370           781,049
-----------------------------------------------------------------------
                                           82,300,704        80,630,918
Investing Activities
 Acquisition of properties                (90,549,403)      (76,153,324)
 Acquisition of a private company
  (Note 4)                                 (3,000,000)                -
 Additions to property, plant and
  equipment                               (27,208,770)         (770,162)
 Site restoration and reclamation            (577,240)                -
 Proceeds on disposition of
  property, plant and equipment                     -           155,150
 Change in non-cash working
  capital balances related to
  investing activities (Note 13)              330,516        (1,889,724)
-----------------------------------------------------------------------
                                         (121,004,897)      (78,658,060)

Increase (decrease) in cash and
 short-term investments                    (4,502,947)        4,502,947

Cash and short-term investments,
 beginning of period                        4,502,947                 -

-----------------------------------------------------------------------
Cash and short-term investments,
 end of period                            $         -       $ 4,502,947
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Cash interest payments                    $ 2,865,684       $ 1,886,921
Cash tax payments                         $   157,382       $         -
Cash distributions declared per
 unit (Note 8)                            $      2.40       $      0.20
-----------------------------------------------------------------------
-----------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

/T/

1. Structure of the trust 

Harvest Energy Trust (the "Trust") is an open-ended, 
unincorporated investment trust formed under the laws of Alberta. 
Pursuant to trust indentures and an administration agreement, the 
Trust is managed by its wholly owned subsidiary, Harvest 
Operations Corp. ("Harvest Operations"). The Trust acquires and 
holds net profit interests in oil and natural gas properties in 
Alberta acquired and held by Harvest Operations and WestCastle 
Energy Inc. ("WestCastle"). The Trust acquires and holds net 
profit interests in oil and natural gas properties in 
Saskatchewan and held by Harvest Sask. Energy Trust. The Trust is 
the sole unitholder of the Harvest Sask. Energy Trust. Harvest 
Operations is the sole shareholder of WestCastle. All properties 
under the Trust, are operated by Harvest Operations. 

The beneficiaries of the Trust are the holders of trust units. 
The Trust makes monthly distributions of its distributable cash 
to unitholders of record on the last business day of each 
calendar month. 

2. Significant accounting policies 

These consolidated financial statements of the Trust have been 
prepared by management in accordance with Canadian generally 
accepted accounting principles ("Canadian GAAP"). 

(a) Consolidation 

These consolidated financial statements include the accounts of 
the Trust and its wholly-owned subsidiaries Harvest Operations, 
WestCastle and Harvest Sask. Energy Trust. All inter-entity 
transactions and balances have been eliminated upon 
consolidation. 

(b) Use of estimates 

The preparation of financial statements requires management to 
make estimates and assumptions that affect the reported amounts 
of assets and liabilities and disclosures of contingencies, if 
any, as at the date of the financial statements and the reported 
amounts of revenues and expenses during the period. Specifically, 
amounts recorded for depletion, depreciation, amortization and 
site restoration and reclamation and amounts used for the ceiling 
test calculation are based on estimates of oil and natural gas 
reserves and future costs required to develop those reserves. By 
their nature, these estimates are subject to measurement 
uncertainty. 

(c) Revenue recognition 

Revenues associated with the sale of the subsidiaries crude oil, 
natural gas and natural gas liquids are recognized when title 
passes from the subsidiaries to their customers. 

(d) Cash and short-term investments 

Short-term investments with maturities less than three months are 
considered to be cash equivalents and are recorded at cost, which 
approximate market value. 

(e) Joint venture accounting 

The subsidiaries of the Trust conduct substantially all of their 
oil and natural gas production activities through joint ventures, 
and the accounts reflect only their proportionate interest in 
such activities. 

(f) Property, plant and equipment 

The Trust follows the full cost method of accounting. All costs 
of acquiring oil and natural gas properties and related 
exploration and development costs, including overhead charges 
directly related to these activities, are capitalized and 
accumulated in one cost center. Maintenance and repairs are 
charged against income. Renewals and enhancements that extend the 
economic life of the capital assets are capitalized. 

Gains and losses are not recognized on disposition of oil and 
natural gas properties unless that disposition would alter the 
rate of depletion by 20% or more. 

Ceiling test 

The Trust places a limit on the aggregate cost of capital assets, 
which may be carried forward for depletion against net revenues 
of future periods (the ceiling test). The ceiling test is a cost 
recovery test whereby the capitalized costs, less accumulated 
depletion and site restoration and the lower of cost and market 
value of unproved land, are limited to an amount equal to 
estimated undiscounted future net revenues from proved reserves, 
less general and administrative expenses, site restoration, 
management fees, future financing costs and applicable income 
taxes. Costs and prices at the balance sheet date are used. Any 
costs carried on the balance sheet in excess of the ceiling test 
limitation are charged to income. 

Site restoration and reclamation provision 

The Trust provides for the cost of future site restoration and 
reclamation, based on estimates by management, using the 
unit-of-production method. Actual site restoration costs are 
charged against the accumulated liability. 

Depletion, depreciation and amortization 

Provision for depletion and depreciation of petroleum and natural 
gas assets is calculated on the unit-of-production method, based 
on proved reserves before royalties as estimated by independent 
petroleum engineers. The basis used for the calculation of the 
provision is the capitalized costs of petroleum and natural gas 
assets plus the estimated future development costs of proved 
undeveloped reserves. Reserves are converted to equivalent units 
on the basis of six thousand cubic feet of natural gas to one 
barrel of oil. 

Depreciation and amortization of office furniture and equipment 
is provided for at rates ranging from 20% to 50% per annum. 

(g) Income taxes 

The Trust and Harvest Sask. Energy Trust are taxable entities 
under the Income Tax Act (Canada) and are taxable only on income 
that is not distributed or distributable to the unitholders. As 
both the Trust and Harvest Sask. Energy Trust plan to distribute 
all of their taxable income to their respective unitholders and 
meet the requirements of the Income Tax Act (Canada) applicable 
to a Trust, neither the Trust nor Harvest Sask. Energy Trust make 
provisions for future income taxes. 

Harvest Operations and WestCastle follow the liability method of 
accounting for income taxes. Under this method, income tax 
liabilities and assets are recognized for the estimated tax 
consequences attributable to differences between the amounts 
reported in its financial statements and its respective tax base, 
using enacted or substantively enacted income tax rates. The 
effect of a change in income tax rates on future tax liabilities 
and assets is recognized in income in the period in which the 
change occurs. Temporary differences arising on acquisitions 
result in future income tax assets and liabilities. 

(h) Unit-based compensation 

The Trust uses the fair value method of accounting for the Trust 
Unit incentive plan (Note 9). Under the terms of the plan, the 
exercise price of rights granted may be reduced in future periods 
based on the distributions made to Trust unitholders. The 
compensation expense is recognized into income over the vesting 
period of the associated unit appreciation right. 

(i) Deferred financing charges 

Deferred financing charges relate to costs incurred on the 
issuance of debt and are amortized on a straight-line basis over 
the term of the debt, and are included in the associated interest 
expense. 

(j) Financial instruments 

Harvest Operations enters into financial instruments to manage 
its exposure to adverse fluctuations in commodity prices, foreign 
currency exchange rates, electricity costs and interest rates. 
Harvest Operation's policy is not to utilize derivative financial 
instruments for trading or speculative purposes. Realized gains 
or losses on financial instruments that are designated and 
assessed effective as hedges are recognized in income 
concurrently with the underlying hedged transaction. If the hedge 
of an anticipated transaction is terminated or ceases to be 
effective, the associated gain or loss at that date is deferred 
and recognized concurrently with the anticipated transaction. 
Subsequent changes in value of the financial instruments are 
reflected in income. Harvest may also enter into debt denominated 
in U.S. dollar as an economic hedge of the impact of foreign 
currency exchange rates on future revenues. 

(k) Foreign currency translation 

Monetary assets and liabilities denominated in a foreign currency 
are translated at the rate of exchange in effect at the balance 
sheet date. Revenues and expenses are translated at the monthly 
average rate of exchange. Translation gains and losses are 
included in income in the period in which they arise. 

(l) Comparative figures 

Certain prior period's comparative figures have been reclassified 
to conform to the current year's presentation. 

3. Changes in accounting policy 

Trust unit incentive plan 

The Trust has elected to prospectively adopt the amendments to 
CICA Handbook section 3870 "Stock-based Compensation and Other 
Stock-based payments". Under this section, the Trust has chosen 
to recognize compensation expense when trust unit rights are 
granted under the trust unit incentive plan with no cash 
settlement features on a prospective basis. As such, compensation 
expense has been calculated on all trust unit rights issued on or 
subsequent to January 1, 2003. The fair value of trust unit 
rights issued has been determined using a binomial option pricing 
model. The binomial model has been utilized by the Trust as it 
allows the calculation of the fair value of a trust unit right 
with a decreasing exercise price, based on the distributions paid 
from the date of issue to the date of vesting. 

As a result of adopting this amendment, the net income for the 
year ended December 31, 2003 has decreased by $234,503. 

4. Acquisitions 

On June 1, 2003, the Trust acquired all of the common shares and 
the Net Profit Interest of a private company. Total consideration 
paid by the Trust was $10.1 million, and consisted of the 
issuance of 625,000 trust units at a price of $10.00 per trust 
unit (Note 8), $3 million in cash and an $850,000 unsecured 
demand promissory note that bears interest at 10% per annum 
effective June 27, 2003. The acquisition has been accounted for 
using the purchase price method. 

On October 16, 2003, the Trust acquired the Carlyle Properties in 
Southeastern Saskatchewan for total consideration of 
approximately $79.5 million before costs and purchase price 
adjustments. The acquisition was partially financed by the issue 
of trust units on October 16, 2003 (Note 8) with the balance 
being funded by Harvest Operations bank facility. 

The following summarizes the estimated fair value of the assets 
acquired and liabilities assumed at the date of acquisition. 
Harvest Operations has not yet completed its final calculation of 
the assets acquired and liabilities assumed and therefore, the 
purchase price allocation maybe subject to change. 


/T/

                                                              Amount
--------------------------------------------------------------------
Acquisition of Private Company
Property, plant & equipment                              $15,400,255
Working capital, net                                      (2,500,745)
Bank debt                                                 (2,799,510)
--------------------------------------------------------------------
                                                          10,100,000
--------------------------------------------------------------------

Acquisition of Carlyle properties
Property, plant & equipment                               79,500,000
--------------------------------------------------------------------

                                                         $89,600,000
--------------------------------------------------------------------
--------------------------------------------------------------------

5. Property, plant and equipment

--------------------------------------------------------------------
--------------------------------------------------------------------
                          December 31, 2003
--------------------------------------------------------------------
                                        Accumulated
                                          depletion,
                                   depreciation and
                             Cost      amortization   Net book value
--------------------------------------------------------------------

Oil and natural gas
 properties          $162,079,020      $(25,977,561)    $136,101,459
Production facilities
 and equipment         47,071,008        (8,345,533)      38,725,475
Office furniture and
 equipment                707,773          (157,476)         550,297

--------------------------------------------------------------------
                     $209,857,801      $(34,480,570)    $175,377,231
--------------------------------------------------------------------
--------------------------------------------------------------------


--------------------------------------------------------------------
--------------------------------------------------------------------
                          December 31, 2002
--------------------------------------------------------------------
                                        Accumulated
                                          depletion,
                                   depreciation and
                             Cost      amortization   Net book value
--------------------------------------------------------------------

Oil and natural gas
 properties          $ 55,188,754      $ (3,841,661)    $ 51,347,093
Production facilities
 and equipment         21,343,287        (1,271,752)      20,071,535
Office furniture and
 equipment                236,295           (23,416)         212,879

--------------------------------------------------------------------
                     $ 76,768,336      $ (5,136,829)    $ 71,631,507
--------------------------------------------------------------------
--------------------------------------------------------------------

/T/

General and administrative costs of $1,311,233 and $174,425 have 
been capitalized during the year ended December 31, 2003 and 
period ended December 31, 2002, respectively. 

All costs are subject to depletion and depreciation at December 
31, 2003. In addition, future development costs of $15.2 million 
(2002 - $9.9 million) are included in depletion and depreciation 
calculations at December 31, 2003. 

In accordance with Canadian GAAP, the Trust has performed a 
ceiling test as at December 31, 2003. Using December 31, 2003 
commodity prices of WTI $US 32.78 per barrel for crude oil and 
AECO $5.87 per mcf for natural gas, resulted in a ceiling test 
excess. 

6. Demand loan 

On October 16, 2003, Harvest Operations Corp. entered into a 
credit agreement with a syndicate of Canadian chartered banks and 
the Alberta Treasury Branches. The revolving reducing demand loan 
provides a borrowing base of $89 million with availability 
reducing by $4.5 million on the last day of each calendar month 
starting January 31, 2004. The demand loan permits drawings in 
Canadian or U.S. dollars, and includes bankers acceptances, 
LIBOR, $10 million in letters of credit and a $3 million mark to 
market facility to be used for financial instrument hedging. The 
demand loan bears interest at rates ranging from 0.25% to 2% 
above the applicable Canadian or U.S. prime depending upon the 
type of borrowing and the debt to annualized cash flow ratio. The 
demand loan is secured by a $150 million debenture with a 
floating charge over all of the assets of the Corporation. The 
distributions payable to the Trust's unitholders, the Equity 
Bridge notes (Note 10), and the convertible debentures (Note 15) 
are subordinate to the obligations of the demand loan. Certain 
restrictive covenants, including a working capital ratio of at 
least one to one and that Harvest maintains a minimum hedging of 
50% and 25% of oil volumes for the first four forward quarters 
and next four calendar quarters respectively, are required to be 
maintained for the purpose of measuring Harvest Operations' 
ability to meet its obligation under the credit agreement. 

7. Site restoration and reclamation 

Site restoration involves the surface clean up and reclamation of 
well site and field production facilities. In addition, certain 
plant facilities will require decommissioning, which involves 
dismantlement of facilities as well as the decontamination and 
reclamation of these lands. Total estimated future costs are 
approximately $29.9 million of which $4.3 million has been 
accrued to December 31, 2003. The board of directors has 
established a notional fund to ensure that cash is available to 
carry out the future site restoration and reclamation work. This 
fund is an allocation restricting utilization of the borrowing 
base under the demand loan, and is currently being accrued at 
$125,000 per month, the monthly accrued amount is reviewed 
annually. The fund is reduced for actual site restoration and 
reclamation expenditures incurred. The balance of the fund as at 
December 31, 2003 was $1,047,760. 

8. Unitholders' capital 

(a) Authorized 

The authorized capital consists of an unlimited number of trust 
units. 

Each trust unitholder is entitled to a beneficiary interest in 
any distribution of the Trust and in any net assets in the event 
of termination or wind-up. Trust units are redeemable at any time 
at the option of the holder. The redemption price is equal to the 
lesser of 95% of the average market price of the trust units 
during a 10 day period commencing immediately after the 
redemption date and the closing market price on the redemption 
date. The total amount payable by the Trust in respect of 
redemptions in any calendar month shall not exceed $100,000. To 
the extent that a unitholder is entitled to a redemption payment, 
it will be satisfied by a cash payment from the Trust or by the 
Trust distributing a pro-rata number of Harvest Operations notes 
or distributing its own notes. 


/T/

(b) Issued

                                            Number of
                                                units         Amount
--------------------------------------------------------------------
Issued for cash on formation (i)                  100   $        100
Initial public offering (ii)                4,312,500     34,500,000
Settlement of debenture (iii)               5,000,000      5,000,000
Cancel the initial units issued on
 formation (i)                                   (100)          (100)
Unit issue costs                                    -     (2,772,003)
--------------------------------------------------------------------
As at, December 31, 2002                    9,312,500   $ 36,727,997

Exercise of warrants (iv)                     150,000        150,000
Special warrant exercise (v)                1,500,000     15,000,000
Acquisitions (vi)                             825,000      8,350,000
Trust unit issue (vii)                      4,312,500     48,645,000
Distribution reinvestment plan
 issuance (iix)                             1,009,006     10,637,657
Share issue costs                                   -     (2,103,917)
--------------------------------------------------------------------
As at, December 31, 2003                   17,109,006   $117,406,737
--------------------------------------------------------------------
--------------------------------------------------------------------

/T/

(i) On July 10, 2002, the Trust issued 100 units for cash 
proceeds of $100. As per the agreement on the initial issuance, 
the units were cancelled upon the completion of the initial 
public offering on December 5, 2002. 

(ii) On December 5, 2002, the Trust issued 3,750,000 trust units 
for $27.6 million, net of a 6% underwriters' fee and $702,003 of 
issue costs. The net proceeds were used to fully repay a loan 
from a corporation controlled by a director of Harvest Operations 
and partially repay the bank loans. In conjunction with this 
initial public offering, the Trust granted the underwriters an 
option, to purchase up to an additional 562,500 trust units at a 
price of $8.00 per unit. On December 17, 2002, the underwriters 
exercised the option; the net proceeds were used to partially 
repay the bank loans. 

(iii) Upon completion of the initial public offering the Trust 
paid the trust debenture principal and interest thereon, by the 
issuance of 5,000,000 trust units and a cash payment of $34,829. 

(iv) On January 24, 2003, 150,000 trust units were issued to a 
corporation controlled by a director of Harvest Operations on the 
exercise of a warrant. The $150,000 in proceeds was added to 
working capital. 

(v) On March 7, 2003, 1,500,000 special warrants were exercised 
into trust units. The special warrants were issued on February 4, 
2003 for $13,700,000 net of a 5% underwriters' fee and 
approximately $550,000 of issues costs. 

(vi) On May 27, 2003, the Trust issued 200,000 trust units at a 
price of $10.50 per trust unit, for consideration of the purchase 
of a crude oil producing property. 

On June 27, 2003, the Trust issued 625,000 trust units at a price 
of $10.00 per trust unit, for partial consideration of the 
purchase of a private company (Note 4). 

(vii) On October 16, 2003, the Trust issued 4,312,500 trust units 
at a price of $12.00 per trust unit, for proceeds of $51.75 
million net of a 6% underwriters' fee and $346,000 of issue 
costs. The net proceeds were used to partially fund the 
acquisition of Carlyle properties in South East Saskatchewan. 

(iix) The following table summarizes the issuance of trust units 
under the distribution reinvestment plan ("DRIP"): 


/T/

                                                 Trust units
Distribution                                          issued
Month            Record Date       Payment Date   under DRIP      Amount
------------------------------------------------------------------------
January      January 31, 2003  February 17, 2003      79,208 $   794,650
February    February 28, 2003     March 17, 2003      73,230     780,223
March          March 31, 2003     April 15, 2003      96,019     907,805
April          April 30, 2003       May 15, 2003      98,535     925,662
May              May 31, 2003      June 16, 2003     103,059     990,697
June            June 30, 2003      July 15, 2003     104,425     989,718
July            July 31, 2003    August 15, 2003      92,818     989,612
August        August 29, 2003 September 15, 2003      88,095   1,007,068
September  September 30, 2003   October 15, 2003      89,578   1,028,349
October      October 31, 2003  November 14, 2003      88,256   1,046,629
November    November 28, 2003  December 15, 2003      95,783   1,177,244
------------------------------------------------------------------------
As at, December 31, 2003                           1,009,006 $10,637,657
------------------------------------------------------------------------
------------------------------------------------------------------------


(c) Per unit information

The following table summarizes the trust units used in calculating
income per trust unit.
------------------------------------------------------------------------
                                                     Period from July 10
                                        Year ended   (date of formation)
                                 December 31, 2003  to December 31, 2002
                                 ---------------------------------------
                                 ---------------------------------------

Weighted average trust units
 outstanding, basic                     12,590,937             1,391,608
Effect of trust unit rights                411,868                87,500
Weighted average trust units
 outstanding, diluted                   13,002,805             1,479,108
------------------------------------------------------------------------

/T/

9. Trust unit incentive plan 

A trust unit incentive plan has been established whereby the 
Trust is authorized to grant non-transferable rights to purchase 
trust units to directors, officers, consultants, employees and 
other service providers to an aggregate of 1,121,000 trust units. 
The initial exercise price of rights granted under the plan is 
equal to the closing market price on the date immediately prior 
to the date the rights are granted and the maximum term of each 
right is not to exceed five years. The exercise price of the 
rights is adjusted downwards from time to time based upon the 
cash distributions made on the trust units if the minimum 
distribution rate is met. The following summarizes the trust 
units reserved for issuance under the trust unit incentive plan: 


/T/

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

                                                            Weighted
                                       Trust unit            average
                                           rights     exercise price
--------------------------------------------------------------------

Granted on November 25, 2002              787,500             $ 8.00
Average reduction in exercise price
 due to distributions                           -              (0.20)
--------------------------------------------------------------------
As at, December 31, 2002                  787,500               7.80

Granted, January 24, 2003                  32,500              10.21
Granted, February 14, 2003                 34,500              10.75
Granted, July 15, 2003                     12,500              10.18
Granted, July 17, 2003                      7,500              10.20
Granted, July 18, 2003                     11,000              10.30
Granted, October 17, 2003                  73,400              12.19
Granted, December 15, 2003                106,250              13.15
Average reduction in exercise price
 due to distributions                          -               (2.02)
--------------------------------------------------------------------
As at, December 31, 2003               1,065,150              $ 6.86
--------------------------------------------------------------------
--------------------------------------------------------------------

/T/

All of the trust unit rights outstanding vest equally over the 
next four years on their anniversary date. 

For purposes of estimating fair value disclosures below, the fair 
value of each trust unit right has been estimated on the grant 
date using the following weighted-average assumptions: 


/T/

--------------------------------------------------------------------
                                                 Period from July 10
                                 Year ended       (date of formation)
                          December 31, 2003     to December 31, 2002
--------------------------------------------------------------------
--------------------------------------------------------------------
Expected volatility                   23.30%                   25.60%
Risk free interest rate                4.08%                    3.00%
Expected life of the trust
 unit rights                        4 years                  4 years
Estimated annual
 distributions per unit               $2.40                    $2.40

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

/T/

For the purposes of pro forma disclosures, the estimated fair 
value of all of the trust unit rights is amortized to expense 
over the vesting periods. The Trust's pro forma net income and 
per trust amounts would have been accounted for as follows: 


/T/

--------------------------------------------------------------------
                                                 Period from July 10
                                 Year ended      (date of formation)
                          December 31, 2003     to December 31, 2002
--------------------------------------------------------------------
--------------------------------------------------------------------
Net income  As reported         $16,710,002               $5,136,093
              Pro forma         $15,422,502               $4,969,520
Income per unit - basic
            As reported         $      1.33               $     3.69
              Pro forma         $      1.20               $     3.57
Income per unit - diluted
            As reported         $      1.29               $     3.46
              Pro forma         $      1.16               $     3.35
--------------------------------------------------------------------
--------------------------------------------------------------------

/T/

During the year ended December 31, 2003 and the period from July 
10 to December 31, 2002, the Trust has recognized $234,563 and 
$4,500 respectively, in compensation expense and included it in 
general and administrative expense in the consolidated statement 
of income and accumulated income. 

10. Equity bridge note 

On July 28, 2003, the Trust entered into two equity bridge note 
agreements, which provide for advances in aggregate of up to $40 
million. The terms and conditions are identical for both 
agreements, which is comprised of a $30 million agreement with a 
corporation controlled by a director of Harvest Operations, and a 
$10 million agreement with a director of Harvest Operations. 

Under the terms of the agreements, interest is paid quarterly in 
arrears and is calculated daily at a fixed rate of 10% per annum. 
The Trust has the option to settle the quarterly interest 
payments with cash or the issue of trust units. If the Trust 
elects to issue trust units, the number of trust units to be 
issued to settle a quarterly payment shall be the equivalent to 
the quarterly payment amount divided by 90% of the most recent 
ten-day weighted average trading price. 

The Trust also has the option to repay the principal amounts 
outstanding at any time. If the Trust chooses to partially repay 
the outstanding principal amount, such payment is to be made in 
cash. If the Trust elects to repay the full principal amount plus 
the accrued quarterly payment at maturity, the Trust then has the 
option to settle its obligation with cash or with the issue of 
trust units. The terms to settle with units is the same as with 
the interest option described above. The outstanding principal 
portion and all accrued and unpaid interest on the equity bridge 
note agreements is due and payable in full on January 1, 2005. 
Security has been provided in the form of a fixed and floating 
debenture on the Trust's NPI. The equity bridge lenders may 
demand payment of the full amount if specified events of default 
under the equity bridge note agreements occur. On September 29, 
2003, the equity bridge note agreements were amended to extend 
the uses permitted under the previous agreements, to include 
repayment of bank debt. As at December 31, 2003, there was $25 
million drawn on the equity bridge notes, and accrued interest of 
$665,069 which was paid subsequent to the year end (Note 15). 
Total interest incurred and paid during the year on the equity 
bridge was $870,274 and $205,205 respectively. Interest in 
respect of the equity bridge notes is a charge to unitholders' 
equity and not included in income. 

11. Income taxes 

Future income taxes reflect the net tax effects of temporary 
differences between the carrying amounts of assets and 
liabilities of Harvest Operations and WestCastle Energy Inc. for 
financial reporting purposes and the amounts used for income tax 
purposes. During 2003, legislation regarding the reduction of 
certain Federal and Provincial corporate income tax rates have 
received Royal Assent. These rate changes are expected to be 
applied in varying degrees over the next five years, and have 
resulted in an effective tax rate of approximately 34% for the 
Trust, to be applied on the temporary difference in the future 
tax calculation. 

The provisions for future income taxes varies from the amount 
that would be computed by applying the combined Canadian federal 
and provincial income tax rates to the reported income before 
taxes as follows: 


/T/

-----------------------------------------------------------------------
                                                    Period from July 10
                                       Year ended    (date of formation)
                                December 31, 2003  to December 31, 2002
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Income before taxes                  $  8,705,346          $  3,910,864

Computed income tax expense
 at the statutory rates of 40.6%
 and 42.1%, respectively                3,536,112             1,646,473
Amount included in Trust
 income                               (13,293,485)           (2,912,280)
-----------------------------------------------------------------------
                                       (9,757,373)           (1,265,807)
Increase (decrease) resulting
 from the following:
 Non-deductible crown
  royalties and other payments            (61,482)                9,400
 Federal resource allowance             2,061,812               (17,000)
 Unit appreciation rights
  expense                                  98,935                     -
 Foreign exchange gain                 (1,281,561)                    -
 Rate change                              794,419
 Other                                    (16,788)                1,407
-----------------------------------------------------------------------

Future income taxes                  $ (8,162,038)         $ (1,272,000)
-----------------------------------------------------------------------
-----------------------------------------------------------------------


-----------------------------------------------------------------------
                                                    Period from July 10
                                       Year ended    (date of formation)
                                December 31, 2003  to December 31, 2002
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Future tax assets:
 Tax pools of oil and natural
  gas in excess of net book
  value                              $  8,782,000           $   552,700
 Resource allowance                     1,203,000               172,000
 Tax loss carryforwards                 1,600,000               547,300

-----------------------------------------------------------------------
Net future tax asset                 $ 11,585,000           $ 1,272,000
-----------------------------------------------------------------------
-----------------------------------------------------------------------

/T/

At December 31, 2003, the Trust has tax pools aggregating $118 
million, including $0.8 million in non-capital losses which will 
expire in 2009. The tax pools exceed the corresponding book 
values by approximately $7.7 million. 

At December 31, 2003, Harvest Sask Energy Trust has tax pools 
aggregating $47.5 million. The corresponding book values exceed 
the tax pools by approximately $4 million. 

At December 31, 2003, Harvest Operations has tax pools 
aggregating $44.8 million, including $4.1 million in non-capital 
losses of which $1.1 million and $3 million expire in 2009 and 
2010, respectively. The tax pools exceed the corresponding book 
values by approximately $24.7 million. 

At December 31, 2003, Westcastle Energy Inc. has tax pools 
aggregating $7.1 million. The tax pools exceed the corresponding 
book values by approximately $7 million. 

12. Financial instruments 

The Trust is exposed to market risks resulting from fluctuations 
in commodity prices, foreign exchange rates and interest rates in 
the normal course of operations. 

(a) Fair values 

Financial instruments of the Trust consist mainly of cash, 
accounts receivable, prepaid expenses, accounts payable and 
accrued liabilities, distributions payable, large corporation 
taxes payable and current debt. As at December 31, 2003, there 
were no significant differences between the carrying amounts of 
these financial instruments reported on the balance sheet and 
their estimated fair value. 

(b) Interest rate risk 

The Trust is exposed to interest rate risk on its long-term debt. 


(c) Credit risk 

Substantially all of the accounts receivable are due from 
customers in the oil and natural gas industry and are subject to 
normal industry credit risks. Concentration of credit risk is 
mitigated by having a broad customer base, which includes a 
significant number of companies engaged in joint operations with 
the Trust. The Trust periodically assesses the financial strength 
of its partners and customers, including parties involved in the 
marketing or other commodity arrangements. The carrying value of 
accounts receivable reflects management's assessment of the 
associated credit risks. 

(d) Foreign exchange rate risk 

The Trust is exposed to the risk of changes in the Canadian / 
U.S. dollar exchange rate on sales of commodities that are 
denominated in U.S. dollars or directly influenced by U.S. dollar 
benchmark prices.  During 2003, the Trust borrowed funds 
denominated in U.S. dollars as an economic hedge of the impact of 
exchange rates on sales during the year.  As at December 31, 2003 
all of the U.S. dollar debt had been repaid. 



(e) Commodity risk management 

The Trust uses oil sales contracts and derivative financial 
instruments to comply with this requirement. Under the terms of 
some of the derivative instruments, Harvest Operations is 
required to provide security from time to time based on the 
underlying market commodity price of those contracts. The Trust 
is also exposed to counterparty risk for theses derivative 
contracts. This risk is managed by diversifying the Trust's 
derivative portfolio among a number of counterparties. 

The following is a summary of the oil sales contracts with price 
swap or collar features as at December 31, 2003, that have fixed 
future sales prices: 


/T/

Commodity collar contracts based on West Texas Intermediate
-----------------------------------------------------------------------
                                                         Mark to Market
Daily                                                        Gain (Loss)
Quantity            Term        Price per Barrel (Note 1)         Cdn $
-----------------------------------------------------------------------
2,500 Bbls/d  January through
               December 2004   U.S. $22.00 - 28.10          $(2,456,677)
1,000 Bbls/d  January through
               December 2004   U.S. $23.00 - 27.95 ($18.00) $(1,095,885)
1,000 Bbls/d  January through
                 December 2004 U.S. $25.00 - 28.25 ($18.00) $  (954,367)
500 Bbls/d    January through
               December 2004   U.S. $27.50 - 31.00 ($20.25) $   154,929
500 Bbls/d   January through
              December 2004    U.S. $27.65 - 33.00 ($21.00) $   (47,173)
-----------------------------------------------------------------------

Note 1 Harvest has sold a put option at the price denoted in
       parenthesis, for the same volumes as the associated commodity
       contract. The counterparty may exercise this option if the
       respective index falls below the specified price on a monthly
       settlement basis.


Commodity swap contracts based on West Texas Intermediate
-----------------------------------------------------------------------
                                                         Mark to Market
Daily                                                        Gain (Loss)
Quantity            Term        Price per Barrel (Note 1)         Cdn $
-----------------------------------------------------------------------
1,510 Bbls/d  January through
               March 2004      U.S. $23.23                 $ (1,553,580)
1,300 Bbls/d  January through
               March 2004      U.S. $24.33                 $ (1,171,187)
500 Bbls/d    January through
               December 2004   U.S. $24.12 ($15.50)        $ (1,441,863)
500 Bbls/d    January through
               December 2004   U.S. $24.25                 $ (1,399,408)
500 Bbls/d    January through
               December 2004   U.S. $29.32                 $   (203,583)
1,430 Bbls/d  April through
               June 2004       U.S. $22.93                 $ (1,297,309)
1,200 Bbls/d  April through
               June 2004       U.S. $25.50                 $ (2,911,765)
1,380 Bbls/d  July through
               September 2004  U.S. $22.70                 $ (1,098,458)
500 Bbls/d    July through
               September 2004  U.S. $24.56                 $   (287,414)
1,325 Bbls/d  October through
               December 2004   U.S. $22.54                 $   (957,680)
500 Bbls/d    October through
               December 2004   U.S. $24.03                 $   (272,808)
500 Bbls/d    January through
               December 2004   U.S. $30.50                 $     74,736
500 Bbls/d    January through
               December 2005   U.S. $24.00                 $   (811,076)
1,100 Bbls/d  January through
               March 2005      U.S. $22.38                 $   (714,041)
1,030 Bbls/d  April through
               June 2005       U.S. $22.18                 $   (652,039)
-----------------------------------------------------------------------


Commodity swap contracts based on the Lloydminster Blend Crude
differential
-----------------------------------------------------------------------
2,000 Bbls/d  January through
               December 2004   U.S. ($7.75)                $  1,368,005
1,000 Bbls/d  January through
               December 2004   U.S. ($8.20)                $    471,726
500 Bbls/d    January through
               December 2004   U.S. ($7.90)                $    306,622
-----------------------------------------------------------------------


The following is a summary of electricity price hedging swap contracts
entered into by Harvest Operations to fix the cost of future electricity
usage as at December 31, 2003:

Commodity swap contracts based on electricity prices
-----------------------------------------------------------------------
                                                                   Mark
                                                Price per     to Market
Quantity               Term                     Megawatt     Gain (Loss)
-----------------------------------------------------------------------
5MW          January through December 2004    Cdn. $46.00    $  384,300
5MW          January through December 2004    Cdn. $46.00    $  384,300
5MW          January through December 2004    Cdn. $45.50    $  406,260
5MW          January through December 2005    Cdn. $43.00    $  153,300
9.75MW       January 2004 through March 2006  Cdn. $44.50    $1,372,920
-----------------------------------------------------------------------


Commodity swap contracts based on electricity heat rate
-----------------------------------------------------------------------
                                                                   Mark
                                                Price per     to Market
Swaps                  Term                      Megawatt    Gain (Loss)
-----------------------------------------------------------------------
5MW          January through December 2005    8.40 GJ/MWh    $   46,253
-----------------------------------------------------------------------


Foreign Currency Contracts
-----------------------------------------------------------------------
Monthly                                                            Mark
Contract                                                      to Market
Amount                 Term                 Contract Rate    Gain (Loss)
-----------------------------------------------------------------------
U.S.
 $3 million  January through December 2004 1.3333 Cdn/U.S.   $1,735,435
-----------------------------------------------------------------------

/T/

At December 31, 2003 the net mark-to-market unrealized loss for 
all the financial derivative contracts entered into by Harvest 
Operations was approximately $12,467,527. Harvest Operations has 
provided a deposit to the counterparties with some of its 
financial derivative contracts, based on the mark-to-market value 
of those contracts at the end of the trading day. As at December 
31, 2003, this amount totaled $11,899,127 and is recorded in the 
prepaid expense and deposits balance. 


/T/

13. Change in non-cash working capital

-----------------------------------------------------------------------
                                                    Period from July 10
                                       Year ended    (date of formation)
                                December 31, 2003  to December 31, 2002
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Changes in non-cash working
 capital items:
 Accounts receivable                 $ (5,589,776)        $ (13,577,870)
 Prepaid expenses and
  deposits                            (11,596,322)             (534,573)
 Accounts payable and accrued
  liabilities                          11,546,159             5,640,176
 Cash distributions payable             1,559,301                     -
 Accrued interest payable                 (57,842)              389,349
 Equity bridge interest
  payable                                 665,069                     -

-----------------------------------------------------------------------
                                     $ (3,473,411)        $  (8,082,918)
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Changes relating to
 operating activities               $ (12,285,485)        $  (6,974,243)
Changes relating to
 financing activities                   2,224,370               781,049
Changes relating to
 investing activities                     330,516            (1,889,724)
Add: Non cash changes                   6,257,188                     -

-----------------------------------------------------------------------
                                    $  (3,473,411)        $  (8,082,918)
-----------------------------------------------------------------------
-----------------------------------------------------------------------

/T/

14. Related party transactions 

A director and a corporation controlled by a director of Harvest 
Operations, have advanced $33.5 million and were repaid $8.5 
million under the equity bridge note during the year ended 
December 31, 2003. The Trust paid $205,205 of the total $870,274 
interest accrued during the year. (Note 10) 

A corporation controlled by a director of Harvest Operations, had 
advanced $25 million and was repaid $25 million under a bridge 
note during the year ended December 31, 2003. The Trust paid 
$71,233 in interest on this bridge note during the year. 

A corporation controlled by a director of Harvest Operations 
exercised warrants to purchase 150,000 trust units for proceeds 
of $150,000 on January 24, 2003. (Note 8) 

A corporation controlled by a director of Harvest Operations 
sublets office space and is provided administrative services at 
fair market value. 

15. Subsequent events 

On January 1, 2004, WestCastle amalgamated with Harvest 
Operations. 

On January 2, 2004, the Trust paid $665,069 of the accrued 
interest payable related to the equity bridge note. (Notes 10 and 
14) 

On January 29, 2004, the Trust closed an issue of 60,000 9% 
convertible unsecured subordinated debentures due May 31, 2009. 
This financing provided proceeds of $60 million. Interest on the 
debentures is payable semi-annually in arrears in equal 
installments on May 31 and November 30 in each year, commencing 
May 31, 2004. The debentures are convertible into fully paid and 
non-assessable trust units at the option of the holder at any 
time prior to the close of business on the earlier of May 31, 
2009 and the business day immediately preceding the date 
specified by the Trust for redemption of the Debentures, at a 
conversion price of $14.00 per trust unit plus a cash payment for 
accrued interest and in lieu of the fractional trust units 
resulting on the conversion. The debentures may be redeemed by 
the Trust at its option in whole or in part subsequent to May 31, 
2007, at a price equal to $1,050 per debenture between June 1, 
2007 and May 31, 2008 and at $1,025 per debenture between June 1, 
2008 and May 31, 2009. Any redemption will include accrued and 
unpaid interest at such time when completed. The Trust may also 
elect to redeem the debentures upon maturity with the issue of 
trust units at a price equal to 95% of the weighted average 
trading price for the preceding 20 consecutive trading days, 5 
days prior to settlement date A settlement in trust units is 
subject to specified notice and regulatory approval. Upon the 
issue of the debentures, the Trust repaid the $25 million equity 
bridge note outstanding as at December 31, 2003 (Note 10), and 
accrued interest of $185,232. 

On February 16, 2004, 13,700 trust unit rights were issued to 
employees under the Trust unit incentive plan with an exercise 
price of $13.35 per unit. The trust unit rights vest equally over 
the next four years on their anniversary date. 

On February 24, 2004, 12,000 trust unit rights were issued to 
employees under the Trust unit incentive plan with an exercise 
price of $13.75 per unit. The trust unit rights vest equally over 
the next four years on their anniversary date. 

Between January 22, 2004 and March 31, 2004 11,250 trust unit 
rights were exercised or settled, of which 5,000 were settled in 
cash for approximately $30,000 by the Trust, and 6,250 trust 
units were issued at an exercise price of $5.20 per unit. Also 
during this period, 15,875 trust unit appreciation rights were 
cancelled. 

On March 15, 2004, $1 million of the convertible debentures 
issued on January 29, 2004 were converted into 71,428 trust 
units. In conjunction with this conversion, the Trust also paid a 
total of $11,350 in cash for accrued interest and in lieu of 
fractional units. 

On March 19, 2004, Harvest Operations entered into a fixed price 
swap to purchase 1,008 GJ of natural gas at $6.05 per GJ, from 
January 1 to December 31, 2005. This contract was purchased with 
the intent to be combined with the previously purchased swap on 
the electricity heat rate for $8.40 GJ/MWh for 5MW during the 
same period. These two instruments in combination, have 
effectively resulted in the purchase of 5 MW of electricity at 
$50.82 per MWh. 


/T/

The following is a summary of the Trust distributions announced and
paid subsequent to the year end:


                                          Trust units
Distribution                             issued under   Total Amount of
Month           Record Date Payment Date         DRIP      Distribution
-----------------------------------------------------------------------

December, 2003  December 31,  January 15,      54,761       $ 3,421,801
                       2003         2004
January          January 31, February 16,      14,870         3,432,753
                       2004         2004
February        February 27,    March 15,      24,980         3,435,774
                       2004         2004
March              March 31,    April 15,      21,825         3,456,300
                       2004         2004
-----------------------------------------------------------------------

/T/

On April 14, 2004 the Trust declared a distribution of $0.20 per 
trust unit payable to unitholders of record on April 30, 2004. 
The distribution payment is estimated to total $ 3,460,671 and 
will be paid on May 14, 2004. 



The following is a summary of the oil sales contracts with price 
swap or collar features that were entered into by Harvest 
Operations subsequent to December 31, 2003, that have fixed 
future sales prices: 


/T/

Commodity collar contracts based on West Texas Intermediate
-----------------------------------------------------------------------
                   Daily                               Price per Barrel
Trade date         Quantity           Term             (Note 1)
-----------------------------------------------------------------------

January 21, 2004   500 Bbls/d    January through       U.S. $28.00 -
                                  June 2005             31.20 ($21.00)
February 20, 2004  500 Bbls/d    January through       U.S. $28.00 -
                                  June 2005             30.70 ($22.00)
February 20, 2004  500 Bbls/d    July through          U.S. $27.50 -
                                  December 2005         29.80 ($22.00)
February 27, 2004  500 Bbls/d    January through       U.S. $28.00 -
                                  June 2005             32.25 ($22.00)
March 10, 2004     500 Bbls/d    January through       U.S. $29.00 -
                                  June 2005             32.50 ($22.00)
March 10, 2004     500 Bbls/d    July through          U.S. $28.00 -
                                  December 2005         31.50 ($22.00)
March 18, 2004     500 Bbls/d    January through       U.S. $29.00 -
                                  June 2005             34.60 ($22.00)
-----------------------------------------------------------------------

Note 1 Harvest has sold a put option at the price denoted in brackets,
       for the same volumes as the associated commodity contract. The
       counterparty may exercise this option if the respective index
       falls below the specified price on a monthly settlement basis.

/T/

16. Commitments and contingencies 

From time to time, the Trust is involved in litigation or has 
claims sought against it in the normal course of business 
operations. Management of the Trust is not currently aware of any 
claims or actions that would materially affect the Trust's 
reported financial position or results from operations. 

The Trust has letters of credit outstanding in the amount of 
approximately $3.3 million, related to electricity infrastructure 
usage. These letters are provided by the Trust's lenders under 
the availability of the demand loan. The letters expire 
throughout 2004, and are expected to be renewed as required. 

Management's Discussion and Analysis 

Management's discussion and analysis ("MD&A") of Harvest Energy 
Trust's ("Harvest" or the "Trust") financial condition and 
results of operations should be read in conjunction with 
Harvest's audited consolidated financial statements and 
accompanying notes for the year ended December 31, 2003. 

Forward-Looking Information 

The following disclosure contains forward-looking information and 
estimates with respect to Harvest. This information addresses 
future events and conditions, and as such involves risks and 
uncertainties that could cause actual results to differ 
materially from those contemplated by the information provided. 
These risks and uncertainties include but are not limited to 
factors intrinsic in domestic and international politics and 
economics, general industry conditions including the impact of 
environmental laws and regulations, imprecision of reserves 
estimates, fluctuations in commodity prices, interest rates or 
foreign exchange rates and stock market volatility. The 
information and opinions concerning the Trust's future outlook 
are based on information available at April 2004. 

Certain Financial Reporting Measures 

The Trust has used certain measures of financial reporting that 
are commonly used as benchmarks within the oil and natural gas 
production industry in the following MD&A discussion. The 
measures discussed are widely accepted measures of performance 
and value within the industry, and are used by analysts and 
investors to compare and evaluate oil and natural gas producing 
entities. These measures are not defined under Canadian generally 
accepted accounting principles ("GAAP") and should not be 
considered in isolation or as an alternative to conventional GAAP 
measures. Certain of these measures are not necessarily 
comparable to a similarly titled measure of another company or 
trust. When these measures are used, they are defined as 
"non-GAAP" and should be given careful consideration by the 
reader. 

Natural gas is converted to an oil equivalent basis ("BOE") 
utilizing a 6 mcf:1 bbl conversion ratio. BOE's may be 
misleading, if used in isolation. A BOE conversion ratio of 6 
mcf:1 bbl is based on an energy conversion method primarily 
applicable at the burner tip and does not represent a value 
equivalency at the wellhead. 

Trust Overview 

Harvest Energy Trust is an oil and natural gas royalty trust, 
which focuses on the operation of high quality, mature producing 
crude oil and natural gas properties. The Trust employs a 
conservative approach to the oil and natural gas production 
business, whereby it acquires high working interest, mature 
producing properties and employs unique management techniques. 
These techniques include diligent, hands-on management to 
maintain and maximize production rates, application of leading 
edge technologies and operating practices, and selective capital 
investment to maximize reservoir recovery, enhancing operational 
efficiencies to control and reduce expenses and unique marketing 
arrangements and corporate hedging techniques to effectively 
manage cash flow. The Trust has operations in the Provost region 
of Eastern Alberta and in the Carlyle region of Southeastern 
Saskatchewan. 


/T/

Industry Overview

----------------------------------------------------------------------
                                        (average for the year)
Prices                                      2003       2002     Change
----------------------------------------------------------------------

West Texas intermediate crude oil
 (US$ per barrel)                        $ 30.99    $ 26.15      18.51%
Edmonton light crude
 ($ per barrel)                            43.77      40.41       8.31%
Lloyd blend crude oil ($ per barrel)       31.48      30.73       2.44%
Bow river blend crude oil ($ per barrel)   32.39      31.77       1.95%
AECO natural gas ($ per mcf)                6.67       4.09      63.08%

Alberta Power Pool electricity
 price ($ per MWh)                         62.99      43.93      43.39%

U.S. / Canadian dollar
 exchange rate (US$)                       0.713      0.637      12.01%
Bank of Canada bank rate                    3.19%      2.70%     18.15%
----------------------------------------------------------------------

/T/

The average price for world crude oil increased year over year, 
with the North American benchmark West Texas Intermediate crude 
oil price averaging U.S. $30.99 in 2003, in comparison with U.S. 
$26.15 for 2002. The price varied throughout the year with a low 
of U.S. $25.24 and a high of U.S. $37.83, primarily due to 
tensions in the Middle East and uncertainty regarding 
international supply. With low inventories, persisting 
uncertainty in Iraq and renewed turmoil a possibility in 
Venezuela, these fluctuating prices are expected to persist 
through at least the first part of 2004. 

The differential between heavy and light crude oil is locally 
recognized in the pricing of Lloyd and Bow River blend crude 
prices. Although heavy differentials widened, heavy prices 
followed light prices increasing slightly during the year by 2.4% 
and 2%, respectively. 

The exchange rate between the U.S. and Canadian dollars changed 
substantially during the year relative to 2002, with the Canadian 
dollar increasing in value by approximately 12% on an average 
annual basis. The increase in closing price year over year was 
even more substantial, with the Canadian dollar closing at 
$0.774US in comparison to $0.635US as at December 31, 2003 and 
2002 respectively. With no indicative signs of the U.S. Federal 
Reserve supporting the U.S. dollar against worldwide currencies, 
the Canadian dollar is anticipated by many to remain strong 
throughout the upcoming year. 

The overall average price increase in WTI of approximately 18.5% 
during the year, is somewhat mitigated by the 12% increase in the 
Canadian dollar versus the U.S. dollar. The bench mark for 
Canadian crude oil prices is the posted price for light crude oil 
delivered to Edmonton ("Edmonton Light"). The average Edmonton 
Light crude price increased 8.3% in 2003. This increase is a 
combination of higher WTI prices offset by a stronger Canadian 
dollar. 

The average Alberta Power Pool electricity price increased 
approximately 43% over 2002, mostly due to the 63% increase in 
the 2003 average AECO natural gas prices. Marginal electricity 
prices are driven by natural gas fired power generation in 
Alberta. There was also as a slight increase of 5.5% in overall 
Alberta consumer demand which contributed to this price increase. 


Acquisitions 

During April and May 2003 Harvest closed the acquisition of 
various interests in two properties in the Killarney area of 
Alberta. On the acquisition date the properties were producing 
approximately 925 BOE/D. The properties, including an interest in 
two oil batteries, were acquired from two major oil and natural 
gas producers for $13.2 million and the issuance of 200,000 trust 
units. The cash consideration was financed through the Trust's 
credit facilities. 

On June 27, 2003, Harvest completed the acquisition of all of the 
common shares and Net Profit Interest ("NPI") of a private 
company in exchange for total consideration of approximately 
$10.1 million (consisting of the issuance of 625,000 Trust Units, 
$3 million in cash and a $850,000 unsecured promissory note) plus 
the assumption of $2.8 million in bank debt and $2.3 million in 
working capital deficit. The oil and natural gas producing 
properties acquired provided production of approximately 1,350 
BOE/d at the acquisition date and include working interests 
ranging from 20% to 100% in the fields of Amisk, Czar and 
Killarney, all of which are operated by the Trust. 

On October 16, 2003, the Trust closed the acquisition of oil and 
natural gas properties producing about 5,100 BOE/d in the Carlyle 
region of Southeastern Saskatchewan. The total consideration for 
the properties was approximately $79.5 million, prior to 
adjustments and transaction costs. 


/T/

Summary of Results

-----------------------------------------------------------------------
                   Year    Period
                  ended     ended
               December  December        Quarterly Information for 2003
Financial      31, 2003  31, 2002       Q4        Q3        Q2       Q1
-----------------------------------------------------------------------

Revenue, net
 of royalties
 and hedging    $84,015   $18,955  $30,474   $21,181   $17,622  $14,738
Operating
 expense         36,045     6,396  $12,984     9,661     6,596    6,804
-----------------------------------------------------------------------
Net operating
 income         $47,970   $12,559  $17,490   $11,520   $11,026   $7,934

Net income       16,710     5,136    6,043     5,751     1,180    3,736
 Per trust
  unit, basic      1.33      3.69     0.37      0.46      0.10     0.36
 Per trust
  unit, diluted    1.29      3.46     0.36      0.45      0.10     0.34
 Per BOE           4.15      6.81     4.42      5.50      1.37     5.05
Cash flow from
 operations      46,487     9,504   13,692    16,759     9,547    6,489
  Per trust
   unit, basic
   (non GAAP)      3.69      6.83     0.85      1.35      0.84     0.62
  Per trust
   unit, diluted
   (non GAAP)      3.58      6.43     0.82      1.31      0.82     0.60
  Per BOE         11.54     12.61    10.02     16.02     11.12     8.77

Sales Volumes
-----------------------------------------------------------------------

Crude oil
 (bbl/d)         10,758     4,181   14,497    11,054     9,371    8,034
Natural gas
 liquids
 (bbl/d)             64        22       70        77        67       43
Natural gas
 (mcf/d)          1,311       624    1,744     1,453     1,161      875
Total (BOE/d)    11,040     4,307   14,858    11,373     9,632    8,223
-----------------------------------------------------------------------

/T/

Sales Volumes 

Harvest's production consists of light, medium and heavy crude 
oil, natural gas liquids, and natural gas from properties located 
in East Central Alberta and Southeastern Saskatchewan. Sales 
volumes, on a barrel of oil equivalent, averaged 11,040 BOE/d, in 
comparison to 4,307 BOE/d for the year ended December 31, 2003, 
and the period ended December 31, 2002, respectively. In the 
fourth quarter of 2003, average crude oil and natural gas sales 
were 14,858 BOE/d with the increase primarily due to acquisition 
of the properties in Saskatchewan in mid October. The average 
daily sales volumes by product were as follows: 


/T/

-----------------------------------------------------------------------
                         Three month             Year            Period
                        period ended            ended             ended
                         December 31,     December 31,      December 31,
                                2003             2003              2002
-----------------------------------------------------------------------
Light and medium
 crude oil (Bbls/d)       8,741   59%      5,314   48%      2,718    63%
Heavy crude oil
 (Bbls/d)                 5,756   39%      5,444   49%      1,463    34%
-----------------------------------------------------------------------
Total oil (Bbls/d)       14,497   98%     10,758   97%      4,181    97%
Natural gas
 liquids (Bbls/d)            70    0%         64    1%         22     1%
-----------------------------------------------------------------------
Total oil and
 natural gas
 liquids (Bbls/d)        14,567   98%     10,822   98%      4,203    98%
Natural gas (mcf/d)       1,744    2%      1,311    2%        624     2%
-----------------------------------------------------------------------
Total oil
 equivalent
 (6:1 BOE/d)             14,858  100%     11,040  100%      4,307   100%
-----------------------------------------------------------------------

/T/

Harvest exited December 31, 2003 with a daily production rate of 
approximately 15,400 BOE/d, a 79% increase year over year, which 
reflects the impact of the ongoing development and optimization 
activities, and acquisitions throughout the year. In comparison, 
the exit rate for the period ended December 31, 2002 was 
approximately 8,600 BOE/d. 

Revenues 

Revenues net of hedging loss and before royalties totaled $100.4 
million and $21.7 million, which was the result of average 
realized prices of $24.95 and $28.79 per barrel of oil equivalent 
for the year ended December 31, 2003 and period ended December 
31, 2002 respectively. For the three month period ended December 
31, 2003, the revenue before royalties was $36.8 million, with an 
average realized price of $26.95 per barrel of oil equivalent. 
The increase in realized prices of approximately 13% in the 
fourth quarter versus the third quarter of 2003, was primarily 
due to the increase in the overall corporate quality (API 
gravity) of crude produced, and the addition of unhedged 
production as a result of the properties acquired in 
Saskatchewan. 


/T/

-----------------------------------------------------------------------
                            Three month           Year           Period
                           period ended          ended            ended
                            December 31,   December 31,     December 31,
                                   2003           2003             2002
-----------------------------------------------------------------------
Product prices:
 Light Oil ($/bbl)                35.56          35.56                -
 Medium Oil ($/bbl)               32.18          30.13            34.21
 Heavy Oil ($/bbl)                27.34          24.92            22.63
 Natural Gas Liquids ($/bbl)      29.92          29.18            37.64
 Natural Gas ($/mcf)               6.70           6.01             4.54
-----------------------------------------------------------------------
 BOE ($/BOE)                      29.13          29.62            30.13
-----------------------------------------------------------------------


Operating Netbacks

The following is a summary of Harvest's operating netbacks:

-----------------------------------------------------------------------
             (Amounts are expressed on a $ per barrel of oil equivalent)
-----------------------------------------------------------------------
                      Three month              Year              Period
                     period ended             ended               ended
                      December 31,      December 31,        December 31,
                             2003              2003                2002
-----------------------------------------------------------------------
Market price               $29.13            $29.62              $30.13
Hedging loss                 2.18              4.67                1.34
-----------------------------------------------------------------------
Realized price              26.95             24.95               28.79

Royalties, net               4.66              4.07                3.64
Operating costs              9.50              8.94                8.49

-----------------------------------------------------------------------
Netback                    $12.79            $11.94              $16.66
-----------------------------------------------------------------------

/T/

Harvest paid net royalties of $16.4 million and $2.8 million 
during the year ended December 31, 2003 and the period ended 
December 31, 2002, or approximately $4.07 per BOE and $3.64 per 
BOE, respectively. The net royalty amount for the year ended 
December 31, 2003 is comprised of $11.1 million in freehold 
royalties and freehold mineral tax, $5.2 million in crown 
royalties and $0.8 million in gross overriding royalties net of 
$0.7 million in royalty income received. In comparison, the net 
royalty amount for the period ended December 31, 2002 was 
comprised of $1.5 million in freehold royalties and freehold 
mineral tax, $1.2 million in crown royalties and $0.2 million in 
gross overriding royalties net of $0.1 million in royalty income 
received. For the three month period ended December 31, 2003, the 
net royalties paid were $6.4 million which is approximately a 3% 
increase with respect to revenue over the previous quarter, due 
to the change in the Harvest royalty structure as the result of 
the addition of the Saskatchewan properties. 

Harvest's operating expenses were $36.0 million and $6.4 million 
or approximately $8.94 and $8.49 per BOE for the year and period 
ended December 31, 2003 and 2002, respectively. For the three 
month period ended December 31, 2003 the operating costs were $13 
million or $9.50 per BOE. Substantially all of the entity's 
properties are operated by Harvest. Approximately 60% of 
Harvest's operating costs are in respect of electricity. 
Management has utilized fixed price delivery contracts to 
mitigate electricity price risk within Alberta. For fiscal year 
2004 Harvest anticipates realizing further benefits from its 
electricity hedges with approximately 25 MWh of its estimated 
Alberta electricity hedged at an average price of $45.34 per MWh. 
This accounts for approximately 89% of the electricity used by 
Harvest in Alberta. 

General and Administration Expenses 

The portion of general and administrative expenditures charged 
against income totaled $4.3 million or $1.08 per BOE for the year 
ended December 31, 2003, in comparison to $0.6 million or $0.77 
per BOE for the period ended December 31, 2002. During the year 
and period ended December 31, 2003 and December 31, 2002, $1.3 
million and $0.2 million, respectively, of general and 
administrative costs were capitalized with regards to field 
enhancement and acquisition activities. For the three months 
ended December 31, 2003, general and administrative expenses were 
$2.2 million which has increased from the third quarter, 
primarily due to the application of the new CICA Handbook 
standard on stock based compensation of approximately $0.2 
million and an increase in general and administrative costs as a 
result of the Saskatchewan property acquisition. 

Interest Expense and Amortization of Deferred Financing Charges 

Interest expense and deferred financing charges amounted to $5.6 
million and $2.6 million for the year and period ended December 
31, 2003 and 2002, respectively. The amortization of deferred 
financing charges associated with fees to secure bank lending 
facilities amounted to $2.6 million and $0.2 million for the year 
and period ended, December 31, 2003 and 2002, respectively. 

Depletion, Depreciation and Amortization and Future Site 
Reclamation Expenses 

Harvest's depletion, depreciation, and amortization and site 
restoration provision totaled $33.7 million and $5.7 million for 
the year and period ended December 31, 2003 and 2002, 
respectively. This balance is comprised of crude oil and natural 
gas properties depletion and depreciation of $29.2 million and 
$5.1 million, approximately $0.2 million and $23,000 for 
depreciation of office furniture and equipment, and $4.4 million 
and $0.5 million for future abandonment and site restoration 
costs period ended December 31, 2003 and 2002, respectively. The 
depletion rate for oil and natural gas properties was 
approximately $7.29 and $6.77 per BOE for the year and period 
ended December 31, 2003 and 2002 respectively, and is based on 
the costs of the oil and natural gas properties purchased, 
capital expenditures incurred and capitalization of general and 
administrative expenses. The $1.08 and $0.72 per BOE rate for the 
year and period ended December 31, 2003 and 2002, respectively, 
used to provide for future site reclamation costs is founded on 
an estimate of ultimate net future expenditures of approximately 
$29.9 million. The depreciation of office furniture and equipment 
and leasehold improvement costs has been calculated on a 
straight-line basis ranging from 20% to 50%. 

Income taxes 

Income taxes for the year and period ended December 31, 2003 and 
2002 ended are comprised of approximately $0.2 million and $0.1 
million in large corporation tax and $8.2 million and $1.3 
million recoveries of future income tax expense, respectively. 
Other than large corporations tax, neither the Trust nor its 
operating subsidiaries are expected to pay cash taxes in 2004. 

Liquidity and Capital Resources 

The Trust's capital investment and operational enhancement 
programs, as well as current and future financial commitments are 
expected to be supported by expected cash flow from operations 
and existing credit facilities while taking into account 
distributions to its unitholders. 

The Trust's cash flow from operations and net income for the year 
ended December 31, 2003 was $46.5 million and $16.7 million, in 
comparison to $9.5 million and $5.1 million respectively, for the 
period ended December 31, 2002. While the strengthening Canadian 
dollar reduced the cash flows from the sales of oil and natural 
gas, the impact was partially offset through the gains realized 
when the US denominated debt was repaid in the third quarter of 
2003. 

As at December 31, 2003 the Trust had working capital, excluding 
demand loan of $9.8 million, in comparison to working capital of 
$10.7 million at the same date in 2002. 

The Trust's net debt (working capital plus demand loan) at 
December 31, 2003 was $53.6 million, which is an increase of 
$18.9 million in comparison to net debt of $34.7 million as at 
December 31, 2002. This increase is the result of property and 
corporate acquisitions throughout the year, which were partially 
financed with bank debt. On September 30, 2003, the Trust changed 
is debt structure by extinguishing a demand loan denominated in 
U.S. dollars, and replacing it with equity bridge financing and a 
credit agreement with a syndicate of Canadian financial 
institutions. This series of transactions has lowered the overall 
effective interest rate on the Trust's demand loan, and has 
consolidated the financing requirements of counterparty 
collateral including a portion of the hedging activity. 

During 2003 the Trust paid $29.1 million in unitholder 
distributions, of which $10.6 million were reinvested through the 
issue of 1,009,006 trust units under the Trust Unitholders' 
Distribution Reinvestment Plan ("DRIP"), this reflects 37% 
participation under the plan. The distributions paid amounted to 
$0.20 per month per trust unit for unitholders on record at the 
last business day of each month. The Trust anticipates 
maintaining this distribution rate in 2004. 

Excluding trust units issued under the DRIP, the Trust issued 6.8 
million trust units during 2003 in relation to an equity 
financing, acquisition of a private corporation, an exercise of 
warrants and the purchase of oil and natural gas properties. 

Capital Expenditures 

Capital expenditures totaled $135.3 million for the year ended 
December 31, 2003, in comparison to $76.9 million for the period 
ended December 31, 2002. Of these expenditures, acquisitions of 
oil and natural gas producing properties in Eastern Alberta 
accounted for approximately $29.2 million, which complement 
Harvest's current operations and production in this area. 
Additionally, Harvest purchased oil and natural gas properties in 
the Carlyle area located in Southeastern Saskatchewan for 
approximately $79.5 million. 

The following table itemizes the balance of non-acquisition 
capital expenditures during the year: 


/T/

-----------------------------------------------------------------------
                                                   ($000's)
-----------------------------------------------------------------------
                                          Year ended       Period ended
                                   December 31, 2003  December 31, 2002
-----------------------------------------------------------------------
Land and undeveloped lease rentals                78                  -
Geological and geophysical                       182                156
Drilling and completion                       10,095                 37
Well equipment, pipelines
 facilities                                   14,521                167
Capitalized general and
 administrative                                1,311                174
Furniture, leaseholds & office
 equipment                                       436                236
Acquisitions                                 108,677             76,153
-----------------------------------------------------------------------
Total capital expenditures                   135,300             76,923
-----------------------------------------------------------------------

/T/

Capital Fund 

The Trust maintains a notional Capital Fund to ensure that funds 
derived from cash flow are available for future acquisitions and 
capital spending. As the Capital Fund is a notional item the fund 
is not specifically segregated in the financial statements. The 
Capital Fund balance is calculated as follows: prior period 
ending balance plus cash flow from operations and amounts 
financed with net proceeds from equity issues net of 
distributions declared payable to unitholders and other equity 
charges (such as interest on Equity Bridge Notes and convertible 
debentures) less capital and acquisition expenditures. The Trust 
does not segregate the Capital Fund nor is a liability recorded 
in the consolidated financial statements. The Trust's policy is 
to retain and contribute up to 50% of cash flow net of 
contributions to the notional Capital Fund. 

At December 31, 2003 the Capital Fund balance is a deficit of 
$14.2 million which represents the portion of capital and 
acquisition expenditures financed with bank debt and working 
capital. 

Future Liquidity Requirements 

Harvest plans to continue with its plan to optimize current 
production with the use of the Capital Fund. From time to time 
the Trust may continue to require external financing, through 
both debt and equity, to maintain its business plan growing 
through acquisitions and execution of efficient capital programs. 
These requirements are subject to external factors including, but 
not limited to fluctuations in equity and commodity markets, 
economic downturns and interest and foreign exchange rates. 
Adverse changes in these factors could require Harvest's 
management to alter the current business plan of the Trust. For 
fiscal year 2004 the Trust anticipates a capital program of 
approximately $34 million which will be funded with the Capital 
Fund, working capital management, prudent use of bank debt, DRIP 
activity and if necessary equity funding. Acquisitions will 
typically be funded with equity financings and additional bank 
debt resulting from an increase in the Trust borrowing base as a 
result of the acquisition. 

The Trust has been able to utilize equity to carry out its 
business plan. The financial capability of the Trust has been 
enhanced by an issue of $60 million convertible debentures 
bearing interest at 9% and issued in January 2004. Access to 
lower cost of capital funding improves the Trust's ability to 
compete and cost effectively carry out its business plan. Upon 
filing of its Annual Information Form in late 2003, the Trust 
became a qualified "POP" issuer, which allows the Trust to use a 
"short form" prospectus for equity financing. This means that the 
Trust can quickly and more easily access equity markets. 

Off-Balance Sheet Arrangements 

The Trust has a number of immaterial operating leases in place on 
moveable field equipment and vehicles. The leases require 
periodic lease payments and are recorded as operating costs. The 
Trust also finances its annual insurance requirements, whereby a 
portion of the annual premium is deferred and paid monthly over 
the balance of the term. 


/T/

Contractual Obligations

The Trust has entered into the following contractual obligations:

                                                  Maturity
                                   ------------------------------------
Annual Contractual Obligation       Less than   Years   Years     After
($ thousands)                          1 year   1 - 3   4 - 5   5 Years
-----------------------------------------------------------------------

Product transportation agreements          35      39      25         -

Operating and premise leases              293     646     646         -

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

/T/

The Trust also had $63.3 million of bank debt outstanding related 
to short term borrowing through its revolving credit facility. 
The Trust intends to extend this facility on an ongoing basis as 
terms permit. 

As at December 31, 2003 Harvest Operations Corp. has entered into 
physical and financial contracts for production with a current 
delivery of approximately 9,800 BOE/d in 2004 and 2,500 BOE/d in 
2005. Harvest has also entered into financial contracts to 
minimize its exposure to fluctuating electricity prices and the 
US / Canadian dollar exchange rate. Please see Note 10 in the 
Consolidated Financial Statements for further details. 

The Trust has entered into a number of insignificant contractual 
obligations under operating leases and normal course oil and 
natural gas business relationships. All of these agreements are 
cancelable on a month to month basis, and do not require 
additional payment upon defeasance. 

Critical Accounting Policies 

The management of the Trust is required to make estimates and 
assumptions that affect the reported amounts of assets and 
liabilities when applying Canadian generally accepted accounting 
principles. The following is a discussion of the accounting 
policies that are deemed critical by management in the 
preparation of the financial results of the Trust. 

Oil and Gas Accounting 

The Trust follows the Canadian Institute of Chartered Accountants 
guideline for the full cost method of accounting for the oil and 
natural gas industry. All costs of acquiring oil and natural gas 
properties and related exploration and development costs, 
including overhead charges directly related to these activities, 
are capitalized and accumulated in one cost center. The 
maintenance and repairs are charged against income, and renewals 
and enhancements that extend the economic life of the capital 
assets are capitalized. Any gains or losses are not recognized on 
disposition of oil and natural gas properties unless that 
disposition would alter the rate of depletion by 20% or more. The 
provision for depletion and depreciation of petroleum and natural 
gas assets is calculated on the unit-of-production method, based 
on proved reserves before royalties as estimated by independent 
petroleum engineers. The basis used for the calculation of the 
provision is the capitalized costs of petroleum and natural gas 
assets plus the estimated future development costs of proved 
undeveloped reserves. Reserves are converted to equivalent units 
on the basis of six thousand cubic feet of natural gas to one 
barrel of oil. The reserve estimates used in these calculations 
can have a significant impact on the net income, and any downward 
revision in this estimate could result in a higher depletion and 
depreciation expense. In addition, a downward revision of this 
reserve estimate could require an additional charge to income as 
a result of the computation of the prescribed ceiling test 
calculation under this guideline. 

Site restoration and reclamation provision 

The Trust provides for the cost of future site restoration and 
reclamation based on estimates by management using the 
unit-of-production method and associated reserve estimates. 
Management estimates the expected future costs to abandon and 
environmentally restore a well or battery site under specific 
environmental legislation. These estimates are characteristically 
difficult to assess due to their expected timing and associated 
costs at that future date. Due to this estimation, any upward 
revision of these expected costs or revisions in timing could 
adversely affect the provision being charged to income. 

Trust unit incentive plan 

The Trust has established a trust unit incentive plan whereby the 
Trust is authorized to grant non-transferable rights to purchase 
trust units to directors, officers, employees, consultants and 
other service personnel. The initial exercise price of rights 
granted under the plan is equal to the closing market price on 
the date immediately prior to the date the rights are granted and 
the maximum term of each right is not to exceed five years. The 
exercise price of the rights is adjusted downwards from time to 
time based upon the cash distributions made on the trust units 
subject to a specific return as outlined in the Trust Units 
Rights Incentive Plan. Under GAAP the Trust records a 
compensation expense based on the binomial model of valuation. 
The binomial model has been utilized by the Trust as it allows 
for the calculation of the fair value of a trust unit right with 
a decreasing exercise price, based on the distributions paid from 
the date of issue to date of exercise. Management is required to 
make certain assumptions and estimates when applying the binomial 
model. Further details regarding the Trust's trust unit incentive 
plan and assumptions and estimates used are included in the Note 
9 of the Consolidated Financial Statements. 

Changes in Accounting Policies 

Trust unit incentive plan 

The Trust has elected to prospectively adopt the amendments to 
CICA Handbook section 3870 "Stock-based Compensation and Other 
Stock-based payments". Under this section, the Trust has chosen 
to recognize compensation expense when trust unit rights are 
granted under the trust unit incentive plan on a prospective 
basis. As such, compensation expense has been calculated on all 
trust unit rights issued on or subsequent to January 1, 2003. The 
fair value of trust unit rights issued has been determined using 
a binomial option pricing model. 

Changes in Accounting Standards 

The following is a list of changes to accounting standards that 
will affect the financial reporting of the Trust in the upcoming 
year as at April 2004: 

Asset retirement obligation 

The CICA has issued a new Handbook section 3110 "Accounting for 
Asset Retirement Obligation" which requires that entities 
recognize the liability associated with the fair value of future 
site reclamation and abandonment costs in the financial 
statements at the time when the liability is incurred. The new 
standard is effective for fiscal years beginning on or after 
January 1, 2004, with earlier adoption encouraged. The Trust has 
elected to adopt this standard in the upcoming fiscal year. 

Full cost accounting guideline 

In September 2003 the CICA issued Accounting Guideline 16 "Oil 
and Gas Accounting - Full Cost". The guideline replaces 
Accounting Guideline 5 "Full Cost Accounting in the Oil and Gas 
Industry" and is effective for fiscal years beginning on or after 
January 1, 2004, with earlier adoption encouraged. Under the new 
guideline the definition for proved and probable reserves has 
been changed to synthesize with the new reserve definitions under 
the recently issued National Instrument 51-101 "Standards of 
Disclosure for Oil and Gas Activities" issued by the Canadian 
Securities Administrators. These changes include modifications to 
the ceiling test calculation, additional disclosure within the 
notes to the financial statements and changes in accounting for 
disposals of properties other than by sale. The Trust has elected 
to adopt this standard in the upcoming fiscal year. 

Hedging 

In December 2001 the CICA issued Accounting Guideline 13 "Hedging 
Relationships" that provides guidance on the identification, 
designation, documentation and measurement of the effectiveness 
of hedging relationships for the purposes of applying hedge 
accounting. This guideline is effective for fiscal years 
beginning on or after July 1, 2003. The Trust has implemented the 
requirements of this guideline in 2003. 

Transactions with Related Parties 

A director and a corporation controlled by a director of Harvest 
Operations Corp., have advanced $60.5 million and were repaid 
$35.5 million during the year ended December 31, 2003. In 
addition interest totaling nearly $0.3 million was paid in 
respect of these advances. Also during the year, a corporation 
controlled by a director of Harvest Operations Corp. exercised a 
warrant to purchase 150,000 trust units for proceeds of $150,000. 
The funds generated in these transactions were used for ongoing 
operations and acquisition activities of the Trust. The terms 
under these agreements and amounts transacted were based upon 
arms length fair market values at the time. A corporation 
controlled by a director of Harvest Operations Corp. sublets 
office space and is provided administrative services at fair 
market value. 

Risk Management Activities 

All of Harvest's risk management activities are carried out under 
policies approved by the Board of Directors. Harvest intends to 
execute its business plan to create value for unitholders by 
paying stable monthly distributions and increasing the net asset 
value per trust unit. Harvest's management has identified the 
following risks associated with the Trust's business: 

- Operational risk associated with the production of oil and 
natural gas; 

- Reserve risk with respect to the quantity of recoverable 
reserves; 

- Commodity price risk, as oil and natural gas prices fluctuate 
due to market forces; 

- Financial risks, such as the Canadian/US dollar exchange rate, 
interest rates, credit risk and debt service obligations; 

- Environmental, health and safety risks associated with well and 
production facilities; and, 

- Changing government policy risks, including revisions to 
royalty legislation, income tax laws, and incentive programs 
related to the oil and natural gas industry. 

Under Harvest's risk management policies approved by the Board of 
Directors the Trust intends to mitigate risks listed above as 
follows: 

Operational risk: 

- Applying a proactive management approach to Harvest's 
properties; 

- Selectively adding educated and experienced employees and 
providing encouragement and opportunities to maintain and improve 
technical competence; and; 

- Remunerating employees with a combination of average industry 
salary and benefits combined with a merit based bonus plan to 
reward success in execution of the Trust's business plan. 

Reserve risk: 

- Acquiring oil and natural gas properties that have high quality 
reservoirs combined with mature, predictable and reliable 
production and thus reduce technical uncertainty; 

- Subjecting all property acquisitions to rigorous operational, 
geological, financial, and environmental review; and 

- Pursuing a capital expenditure program to reduce production 
decline rates improve operating efficiency and increase ultimate 
recovery of the resource in place. 

Commodity price risk: 

- Maintaining risk management policy and committee to 
continuously review effectiveness of existing actions, identify 
new or developing issues and devise and recommend to the Board of 
Directors action to be taken; 

- Maintaining a program to hedge (via utilizing swaps, collars 
and option contracts) commodity prices and electricity costs with 
a portfolio of credit worthy counterparties; and 

- Maintaining a low cost structure to maximize product netbacks. 

Financial risk: 

- Monitoring financial markets to ensure the cost of debt and 
equity capital is kept as low as reasonably possible; 

- Retaining up to 50% of the funds available for distribution to 
finance capital expenditures and future property acquisitions; 

- Monitoring the Trust's financial position and foreign exchange 
markets with the intent of taking the steps necessary to minimize 
the impact of fluctuations in foreign currency; 

- Comparing actual financial performance against pre-determined 
expectations and making changes where necessary; and 

- Carrying adequate insurance to cover losses and business 
interruption. 

Environmental, health and safety risks: 

- Adhering to the Trust's safety program and keeping abreast of 
current industry practices; and 

- Accumulating sufficient cash resources to pay for future 
abandonment and site restoration costs. 

Regulatory risks: 

- Retaining an experienced, diverse and actively involved Board 
of Directors to ensure good corporate governance; and 

- Engaging technical specialists when necessary to advise and 
assist with the implementation of policies and procedures as a 
result of the changing regulatory environment. 

As at December 31 2003, Harvest Operations Corp. has entered into 
market price, physical contracts with a current average delivery 
of approximately 5,825 BOE/d for 2004 and 1,000 BOE/d for 2005. 
Harvest has also entered into financial swap and collared 
contracts for WTI crude oil, LLB differential, US / Canadian 
dollar exchange rate, electricity and natural gas heat rate which 
had a mark to market unrealized loss of $12.5 million as at 
December 31, 2003. Please refer to Note 10 in the Consolidated 
Financial Statements for further information. 

The following table summarizes the risk management activities 
undertaken by the Trust, the volumes hedged and the associated 
unrecognized mark to market gains and losses as at December 31, 
2003: 


/T/

----------------------------------------------------------------------
                                                         Maturity
----------------------------------------------------------------------

                                                   2004    2005   2006
----------------------------------------------------------------------


Volumes Hedged

West Texas intermediate crude oil price based
 swaps (bbls/d)                                   4,286   1,033      -

West Texas intermediate crude oil price based
 collars (bbls/d)                                 5,500       -      -

Lloyd blend crude oil price based swaps
 (bbls/d)                                         3,500       -      -

Alberta electricity price based swaps (MW)           25      15      3

Electricity heat rate (GJ/MWh)                        -       5      -

Canadian / U.S. dollar based swap
(Cdn $ million)                                       3       -      -
----------------------------------------------------------------------


Mark to Market Gains (Losses) ($ thousands)

West Texas intermediate crude oil price based
 swaps                                          (12,520) (2,177)     -

West Texas intermediate crude oil price based
 collars                                         (4,399)      -      -

Lloyd blend crude oil price based swaps           2,146       -      -

Alberta electricity price based swaps             1,785     763    153

Electricity heat rate                                 -      46      -

Canadian / U.S. dollar put option                 1,735       -      -
----------------------------------------------------------------------
                                                (11,253) (1,368)   153

/T/

Under Harvest's risk management policy Management enters into 
crude oil based financial and physical contracts to mitigate the 
risk of price volatility for its expected production. Management 
also enters into electricity price based swaps to assist in 
maintaining stable operating costs. Finally, as a further means 
to manage revenue risks, Management has entered into foreign 
exchange contracts to minimize the effect of adverse foreign 
exchange fluctuations of the Canadian dollar against the U.S. 
dollar. Readers are advised to refer to the Consolidated 
Financial Statement notes of Harvest for the year ended December 
31, 2003 for additional information on these contracts. 

Taxability of Cash Distributions paid to Unitholders 

Cash distributions are comprised of a return of capital portion 
(tax deferred) and a return on capital portion (taxable). For 
cash distributions received by a Canadian resident, outside of a 
registered pension or retirement plan the distribution declared 
in December 2002 and paid in January 2003 was deemed to be 100% 
tax deferred. For the distributions declared in 2003 and paid in 
the months of February 2003 through to January 2004, 41% of the 
distributions are taxable and 59% are a tax deferred. 

Key Performance Indicators and 2004 Outlook 

Based upon current operations, the following table provides 
guidance in respect to 2004 and relative performance for the past 
year: 


/T/

----------------------------------------------------------------------
                                    Performance Goals          Results
                                                 2004             2003
------------------------------------------------------ ---------------

Daily production (BOE/d)              15,000 - 15,500           11,040

Average Royalty Rate                         15% - 16%            13.8%

Operating expense ($/BOE)             $10.00 - $10.50            $8.94

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

/T/

Harvest plans to continue with its business plan of acquiring and 
operating high quality, mature crude oil and natural gas 
properties that are enhanced through operational and exploitation 
techniques. Harvest also plans to continue to identify new areas 
in the Western Canadian sedimentary basin that can provide the 
required growth and stability for sustainable distributions and 
asset value per unit. 

It is important to note that the above figures are estimates 
based upon Management's current expectations. The ultimate 
results may vary, perhaps materially. 

The table below indicates the impact of changes of key variables 
on Harvest's cash flow and distributions including the impacts of 
the hedging program. 


/T/

Sensitivities

-----------------------------------------------------------------------
                                            Variable
                -------------------------------------------------------
                                                      Canadian
                           Heavy Oil LLB                  bank  Foreign
                       WTI  differential    Crude Oil    prime exchange
                 price/bbl          /bbl   production     rate Cdn./U.S.
-----------------------------------------------------------------------
Assumption       $32.00 US      $9.00 US 15,200 boe/d    4.25%     1.32

Change
 (plus or minus) $ 1.00 US      $1.00 US  1,000 boe/d    1.00%     0.01


Cash flow from
 operations
 ($000's)        $   1,700      $  1,900       $6,300   $ 421     $ 800

Per trust unit,
 basic           $    0.10      $   0.11       $ 0.36   $0.03     $0.05

Per trust unit,
 diluted         $    0.10      $   0.11       $ 0.36   $0.03     $0.05


Payout ratio           2.0%          2.3%         7.5%    0.5%     1.0%

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


Harvest Energy Trust
1900, 330 - 5th Avenue S.W.
Calgary, AB T2P 0L4
Canada

/T/

ADVISORY: Certain information regarding Harvest Energy Trust and 
Harvest Operations Corp. including management's assessment of 
future plans and operations, may constitute forward-looking 
statements under applicable securities law and necessarily 
involve risks associated with oil and natural gas exploration, 
production, marketing and transportation such as loss of market, 
volatility of prices, currency fluctuations, imprecision of 
reserve estimates, environmental risks, competition from other 
producers and ability to access sufficient capital from internal 
and external sources. As a consequence, actual results may differ 
materially from those anticipated in the forward-looking 
statements. 

-30-


FOR FURTHER INFORMATION PLEASE CONTACT:

FOR FURTHER INFORMATION PLEASE CONTACT:
Harvest Energy Trust
Jacob Roorda
President
(403) 265-1178

or

Harvest Energy Trust
David M. Fisher
Vice President, Finance
(403) 265-1178
(403) 265-3490 (FAX)
Email: information@harvestenergy.ca
Website: www.harvestenergy.ca