For the three and six months ended June 30, 2006 compared to the same period in 2005 AECO natural gas daily prices saw a decrease of 18% and 6%, respectively, while monthly prices for the same periods decreased by 15% during the quarter and saw an 11% increase during the six month period.

For the second quarter of 2006, our light to medium realized price increased 22% while the Edmonton Par increased by 20%, for the same period. We would expect the change in our realized light to medium price to be slightly higher as a portion of our light to medium production is sold based on the Bow River price, which increased by 53% for the same period. For the six months ended June 30, 2006, our light to medium realized price increased by 15% over the prior year while Edmonton Par increased by 16% over the same periods. Our realized price increase for the six months ended June 30, 2006 over the same period in 2005 is slightly lower than the Edmonton Par increase due again to a portion of our light to medium oil being sold at a Bow River price which traded at a 42.0% differential to Edmonton Par during the first quarter of 2006. Overall, our realized price increase for light to medium oil is consistent with the change in the benchmark prices.

Our transportation costs are primarily related to our costs of delivering natural gas to Alberta's natural gas sales hub, the AECO Storage Hub, and to a much lesser extent, our costs of trucking crude oil to pipeline receipt points.

As the addition of the Viking properties and the Hay River properties to our portfolio significantly impacts comparability between the second quarter of 2006 and the second quarter of 2005, it may be more meaningful to compare the second quarter of 2006 to the first quarter of 2006. Our second quarter of 2006 operating expenses increased by $10.5 million compared to the first quarter of 2006. The most significant portion of the increase (approximately $8.8 million) is attributable to having three full months of operating expenses attributable to the properties acquired in the Viking acquisition in the second quarter as compared to two months in the first quarter of 2006. The remainder of the increase is due to higher well servicing, workovers and well maintenance activity. In the second quarter we are not only seeing higher cost associated with services, but have more properties requiring servicing as well.

As noted, electricity costs represent a significant portion of our operating costs (approximately 20% in the second quarter of 2006 and 22% year to date) and with generally rising electricity prices, particularly in Alberta, our operating expenses can be significantly impacted. In the second quarter of 2006, electricity costs per megawatt hour ("MWh") were 4% higher than they were in the second quarter of 2005. These increases were offset by the Viking properties which have lower power usage per barrel of production, and the Hay River properties which operate using internally generated power. The combination of these two factors, as well as the impact of our fixed price electricity contracts, has resulted in a lower per boe power cost despite rising prices. For the six months ended June 30, 2006, we are seeing similar results. With a 13% increase in the per MWh cost of power we experienced a 4% decrease in our per boe power costs which is attributed to the same factors noted above. The following table details the power costs per boe before and after the impact of our hedging program.

Approximately 65% of our estimated Alberta electricity usage is protected by fixed price purchase contracts at an average price of $51.48 per MWh through December 2006. Of our estimated 2007 and 2008 Alberta electricity usage, 52% is protected at an average price of $56.69 per MWh These contracts will help moderate the impact of future cost swings, as will capital projects undertaken in 2006 and future periods that are dedicated to increasing our power efficiency.

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(1) Includes amounts realized on WTI, heavy price differential and foreign exchange contracts, and excludes amounts realized on electricity contracts.

(2) Includes realized gain on electricity risk management contracts of $0.05 per boe for the three months ended June 30, 2006 and 2005 and $0.07 and $0.05 for the six months ended June 30, 2006 and 2005.

(3) These are non-GAAP measures; please refer to "Non-GAAP Measures" in this MD&A.

Operating netback represents the total net realized price we receive for our production after direct costs. Our operating netback is $9.03 and $7.34 per boe higher for the three and six months ended June 30, 2006 than for the same periods of 2005. The increase is a result of higher commodity prices enabling us to realize a price per boe that is $10.79/boe ($8.86/boe for the six month period) higher, lower losses realized on our hedging program of $3.08/boe ($3.46/boe for the six month period) offset by higher royalties of $2.16/boe ($2.50/boe for the six month period) and higher operating costs (including transportation) of $2.68/boe ($2.48/boe for the six month period).

Interest expense for the three and six months ended June 30, 2006 was higher by $4.2 million and $6.7 million, respectively than for the same period in the prior year primarily due to additional convertible debentures outstanding in the second half of 2005, and convertible debentures assumed with our acquisition of Viking. Compared to the first quarter of 2006, the current quarter interest expense is $2.1 million higher, as a full three months of additional interest expense on bank debt and convertible debentures assumed through our merger with Viking was incurred in the second quarter.

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At June 30, 2006, we had five series of convertible debentures outstanding, including a 10.5% and 6.40% series, which were assumed in conjunction with the Viking acquisition. Details of the terms of each convertible debenture are outlined in Note 8 of the consolidated financial statements for the three months and six months ended June 30, 2006. Interest on the convertible debentures is reported based on the effective yield of the debt component of the convertible debentures. Interest expense on convertible debentures for the three months and six months ended June 30, 2006, is $4.3 million and $7.1 million higher respectively, compared to the same period in 2005, as it includes interest expense on approximately $245.5 million of additional convertible debentures that have been issued by Harvest or assumed from the merger with Viking since June 30, 2005. Though holders of the 9%, 8%, 6.5% and 10.5% convertible debenture series have continued to convert many of their convertible debentures to Harvest Trust Units, the associated reduction in interest expense is not sufficient to offset the additional interest associated with the more recently issued or assumed convertible debentures. In future quarters, interest expense on convertible debentures, not considering future conversions, should remain relatively consistent with the interest expense in the second quarter of 2006, as a full three months of interest expense on the convertible debentures assumed in the Viking's acquisition has been incurred in the quarter. During the quarter, $2.4 million of convertible debentures were converted to Trust Units ($7.2 million for the six months ended June 30, 2006).

Our U.S. dollar denominated senior notes, which bear interest at 7 7/8%, mature on October 15, 2011 and have a fourth year redemption feature, provide an offset to fluctuations in currency exchange rates. Interest expense for the three and six months ended June 30, 2006 on these notes has remained relatively consistent with the same period in 2005, with any fluctuations attributed to volatility in the Canadian dollar to U.S. dollar exchange rate.

Included in total interest expense is the amortization of the discount on the senior notes, the accretion on the debt component balance of the convertible debentures to face value at maturity, as well as the costs incurred to secure credit facilities, all totaling $1.2 million and $2.9 million, respectively, for the three and six months ended June 30, 2006 ($1.7 million and $3.4 million for the three and six months ended June 30, 2005).

Our overall depletion, depreciation and accretion (DD&A) expense for the three and six months ended June 30, 2006 is $59.8 million and $103.5 million higher compared to the same period in 2005. $27.9 million of the increase for the three months ended June 30, 2006 ($49.0 million for the six months ended June 30, 2006) is due to the incremental production from the acquisitions made in the latter half of 2005 and the merger with Viking in the first quarter of 2006 and $31.9 million of the increase for the three months ended June 30, 2006 ($54.5 million for the six months ended June 30, 2006) is due to a higher

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depletion rate also reflecting the Hay River and Viking acquisitions. These acquisitions have increased our overall corporate DD&A rate due to their higher cost as compared to prior property acquisitions.

Foreign exchange gains and losses are attributed to the changes in the value of the Canadian dollar relative to the U.S. dollar on our U.S. dollar denominated senior notes, as well as any other U.S. dollar deposits and cash balances. At June 30, 2006, the Canadian dollar strengthened against the U.S. dollar compared to December 31, 2005, and we incurred an unrealized gain on our senior notes of $11.7 million, which was partially offset by unrealized losses on U.S. dollar deposits of $0.2 million, as well as realized losses on other U.S. denominated transactions, for total foreign exchange gain of $11.5 million reported in the first six month of 2006.

The deferred charges balance on the balance sheet is comprised of four main components: deferred financing charges, discount on senior notes, premium on our office lease and for 2005, deferred charges related to the discontinuation of hedge accounting principles. The deferred financing charges relating to the issuance of the senior notes, convertible debentures and bank debt are amortized over the life of the corresponding debt. The following table provides a summary of the components of the deferred charges at June 30, 2006 as compared to 2005.

In the first quarter of 2006, $0.9 million of deferred charges were added to our balance sheet with respect to an office lease assumed through our acquisition of Viking which had a contracted rate per square foot less than current market rates. This lease extends until February 2010 and the related deferred charge will be amortized over the remaining lease period. Additions to deferred financing costs in the first quarter of 2006 relate to the execution of our new credit agreement on February 3, 2006.

At June 30, 2006 our deferred credit balance was $1.0 million of which $65,000 related to the discontinuation of hedge accounting principles ($398,000 at December 31, 2005). This amount will be fully amortized by the end of 2006. The remaining deferred credit balance on the consolidated balance sheet includes a leasehold improvement credit of $916,000, relating to the leasehold improvement costs reimbursed by the landlord. The credit is amortized over the lease term as a reduction of rent expense.

Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the fair value for accounting purposes, of the net identifiable assets and liabilities of that acquired business. At June 30, 2006, we have recorded $656.2 million of goodwill on our balance sheet, compared with $43.8 million at December 31, 2005. In

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conjunction with our acquisition of Viking for total consideration of $1,975.3 million, we recorded $612.4 million of goodwill. The goodwill balance is assessed annually for impairment or more frequently if events or changes in circumstances occur that would reasonably be expected to reduce the fair value of the acquired business to a level below its carrying amount.

For the three and six months ended June 30, 2006, we have not recorded a future income tax balance on our balance sheet as our total deductible temporary differences exceeded our taxable temporary differences such that an asset was created. As we do not expect we will be able to recover the asset, we have not recorded it on our balance sheet. For the three and six months ended June 30, 2006 we recorded a future income tax recovery of nil and $2.3 million respectively ($3.8 million and $29.8 million for the three and six months ended June 30, 2005). The significant recovery in the six months ended June 30, 2005 related to losses recorded in the corporate subsidiaries of the Trust.

In connection with a property acquisition or development expenditure, we record the fair value of the ARO as a liability in the same year as the expenditure occurs. Our ARO costs are capitalized as part of the carrying amount of the assets, and are depleted and depreciated over our estimated net proved reserves. Once the initial ARO is measured, it must be adjusted at the end of each period to reflect the passage of time as well as changes in the estimated future cash flows of the underlying obligation.

Our asset retirement obligation increased by $79.1 million in the first half of 2006 relative to December 31, 2005. As a result of the merger with Viking, we added $60.5 million to our ARO, and the remainder of the increase in the year to date is due to additions resulting from drilling activity in the first six months of the year, an increased estimate of existing liabilities, and accretion expense, offset by actual asset retirement expenditures made in the period.

The non-controlling interest represents the value attributed to outstanding exchangeable shares of Harvest Operations. The exchangeable shares were originally issued by Harvest Operations as partial consideration for the purchase of a corporate entity in 2004. The exchangeable shares rank equally with the Trust Units and participate in distributions through an increase in the exchange ratio applied to the exchangeable shares when they are ultimately converted to Trust Units.

Under the plan of arrangement with Viking, exchangeable shareholders were able to convert their exchangeable shares of Harvest Operations into Trust Units. As a result 156,067 exchangeable shares were converted from January 1, 2006 to June 19, 2006, leaving a balance of 26,902 outstanding at June 19, 2006 compared to a balance of 182,969 at December 31, 2005.

On March 16, 2006, we announced our intent to exercise our de minimus redemption right on the remaining 26,902 exchangeable shares outstanding. As a result, each redeemed exchangeable share was purchased for a total cash payment of $1.0 million.

The net income attributed to non-controlling interest holders for three months ended June 30, 2006 was $15,000 ($120,000 for the three months ended June 30, 2005) versus a gain of $65,000 for the six months ended June 30, 2006 ($375,000 gain for the six months ended June 30, 2005).

At the end of the second quarter of 2006, our bank borrowings totaled $227.5 million and we had an undrawn credit capacity of $672.5 million pursuant to a $900 million three year extendible revolving credit facility essentially unchanged from the $201.7 million outstanding and $698.3 million available at the end of March 2006. This syndicated credit facility currently matures on February 3, 2009, if not extended prior thereto.

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During the three months ended June 30, 2006, our Cash Flows totaled $147.0 million, excluding $670,000 of one time cash transactions costs, compared to $101.0 million in the first quarter of 2006 which excludes $5.1 million of one time cash transaction costs incurred in the first quarter. Distributions, net of participation in our reinvestment plans, totaled $65.9 million in the current quarter with total cash capital expenditures totaling $54.5 million resulting in excess cash of approximately $26.7 million before working capital adjustments. During the first six months of 2006, Cash Flows totaled $248.0 million (excluding one time cash transactions costs of $5.7 million) with distributions, net of proceeds from our reinvestment plan, aggregating to $111.2 million and capital spending totaling $181.1 million including $23.7 million in respect of property acquisitions within our core assets. Our working capital requirements and bank borrowings at the end of June 2006 reflect the impact of both marginally higher commodity prices and the second quarter's lower level of capital spending relative to the first quarter of 2006. These Cash Flows represent a significant increase over the $57.2 million and $109.9 million earned over the comparative three month and six month period in 2005 primarily due to the acquisition of Viking in February 2006 and the Hay River assets in August 2005 as well as increased commodity prices.

Distributions declared for the six months ended June 30, 2006 totaled $210.7 million representing 85% of Cash Flow. Of the total distributions declared, $99.5 million have been settled with Trust Units as a result of Unitholders choosing to participate in our distribution reinvestment plans, which represents a participation rate of approximately 47%, as adjusted for the one month delay between the declaration and payment of distributions.

The availability of funds under our $900 million credit facility is subject to quarterly financial covenants requiring that the Senior Debt to Cash Flow Ratio be less than 3 to 1, the Total Debt (excluding convertible debentures) to Cash Flow Ratio be less than 3.5 to 1, Senior Debt to Capitalization be less than 50% and Total Debt to Capitalization be less than 55%, all as defined in the Credit Agreement. At the end of June 2006, our Senior Debt to Cash Flow Ratio was 0.4 to 1.0, the Total Debt (excluding convertible debentures) to Cash Flow Ratio was 0.9 to 1.0, Senior Debt to Capitalization was 8% and Total Debt to Capitalization was 17%. During the first half of 2006, holders of $7,152,000 of convertible debentures elected to convert their holdings to trust units resulting in the issuance of 273,280 trust units and resulting in our total debt, including convertible debentures, being 25% of total capitalization at the end of June 2006.

On July 26, 2006, we announced a definitive agreement to acquire a private western Canadian oil and natural gas producer with an anticipated closing in mid-August for cash consideration of approximately $440 million. Concurrent with this acquisition, we entered into a further agreement to sell on a bought deal basis, subject to regulatory approval, 6,110,000 trust units at a price of $32.75 per trust unit for gross proceeds of $200.1 million to a syndicate of Canadian underwriters. In addition, the underwriters have an over allotment option for an additional 916,500 trust units for gross proceeds of $30.0 million. Subsequent to the closing of the acquisition and the equity financing, our bank debt to total capitalization and total debt (excluding convertible debentures) would be 14% and 22%, respectively. Following our announcement, the Dominion Bond Rating Service Limited ("DBRS") confirmed the STA-5 (low) rating for Harvest noting the high cost of the acquisition as reflective of a broader industry trend with more emphasis placed on probable reserves in evaluating acquisitions in a highly competitive environment. DBRS also recognized that the acquisition fits well with our existing assets providing a high degree of certainty regarding expectations of future production and that the 50:50 debt plus equity financing should result in a modest decline in our payout ratio.

Concurrent with the above acquisition, we have increased our capital expenditure program for the year to $300 million to provide for $25 million to be spent on the acquired properties over the remainder of the year and an additional $25 million relating to an update of our plans for our existing assets. With expected undrawn credit lines of more than $400 million subsequent to closing both the acquisition and equity financing, we anticipate that our liquidity will be sufficient to fund our capital spending program and our planned distributions while Unitholder participation in our distribution reinvestment plan enables us to accelerate debt repayment.

At the beginning of the quarter, our trust units were trading around $34.00 with prices reaching $35.80 by late April and closing the quarter at $33.21. The units were actively traded on the Toronto Stock Exchange as well as the New York Stock

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(6) Represents the undiscounted obligation by period

We have a number of operating leases in place on moveable field equipment, vehicles and office space and our commitments under those leases are noted in our annual contractual obligations table above. The leases require periodic lease payments and are recorded as either operating costs or G&A. We also finance our annual insurance premiums, whereby a portion of the annual premium is deferred and paid monthly over the balance of the term.

Harvest incurred $54.2 million of expenditures, including $26.8 million on drilling activities to drill 37 gross (23.2 net) wells during the second quarter of 2006 compared to $26.2 million and 26 net wells for the same period in the prior year. The activity reflects our increased focus on internally developed projects to exploit identified opportunities on our asset base.

In the second quarter of 2006, we continued our development drilling program in Markerville, drilling 7 gross (3.4 net) wells to the Edmonton Sands and Pekisko formations. In the second quarter of 2006, we continued the drilling program we initiated in the first quarter of 2006 in South East Saskatchewan and Red Earth by drilling an additional 4 and 3 gross and net wells in those areas. We also implemented our planned drilling program in Lloyd and Suffield. Suffield is our largest single producing property and we are drilling horizontal wells into the Glauconite formations. For the wells drilled in Lloyd, South East Saskatchewan, Red Earth, and Suffield we expect production from these wells to come on in the third quarter of 2006. Two additional wells were drilled in Wainwright adding to the 12 that were drilled in the first quarter of 2006.

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The $54.2 million capital spending in the second quarter includes $2.4 million spent on land acquisitions including the acquisition of 27 sections (equivalent to 17,280 gross and net acres) of oil sands leases in our Northern Alberta area, adjacent to our Red Earth property. This acquisition expands our rights in the area to include the oil sands horizon in addition to the conventional productive hydrocarbon zones, and brings our total oil sands rights to 26,200 gross and net acres. We also incurred miscellaneous capital costs in the quarter on routine optimizations and recompletions and incurred additional costs on our water handling upgrade in Suffield. These water handling upgrades will improve our ability to optimize production on both the new drilling as well as the existing wells. This upgrade is now nearly complete with the final pumping upgrade to be completed in the fall. We should begin to see the benefits in increased productive capacity and recoverable reserves of this upgrade in the area by the beginning of the fourth quarter of 2006. In the second quarter of 2006, we also incurred additional costs in Hay River relating to tying in of wells drilled in the first quarter, completions, facility modifications and servicing activities.

The following summarizes our participation in gross and net wells drilled during the second quarter of 2006:

The following summarizes our participation in gross and net wells drilled for the six months ended 2006:

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In the second quarter of 2006, we declared distributions of $1.14 per Trust Unit ($115.9 million) to Unitholders. This represents a 90% increase in distributions declared over the $0.60 per Trust Unit declared in the second quarter of 2005. The aggregate of distributions declared during the second quarter of $115.9 million reflects an increase in distributions on a per-Trust Unit basis over 2005 as well as an increase in the number of Trust Units outstanding of approximately 58 million following the acquisition of Viking and Hay River and continued DRIP participation.

(1) Cash flow excludes working capital changes, settlements of asset retirement obligations and one time transaction costs associated with the Viking acquisition see Non-GAAP measures.

The Trust is subject to tax on its taxable income less the portion that is paid or payable to the Unitholders at the end of each taxation year. As such, we expect that the current year distributions to our Unitholders will be 100% taxable.

Prior to inclusion of our recently announced acquisition, we anticipated our daily production would average 60,000 to 62,000 boe/day for the period from August through December 2006. For the month of July, we experienced a loss of approximately 3,500 boe/d resulting from an explosion and fire at a partner-operated gas plant that processes our Markerville production, and continue to have approximately 500 boe/d behind pipe which is expected to come on stream through the third quarter. Combining the 6,300 boe/d of production added from the acquisition for 5 months, we anticipate our 2006 annual production will average approximately 60,000 boe/d with an expected exit rate of approximately 66,000 boe/d. We anticipate that during the last half of 2006, we will continue the tie-in of our behind pipe volumes currently estimated to be approximately 1,600 boe/d.

Our operating costs for the full year 2006 are estimated to approximate $10.50 per boe considering the impact of our acquisition. The acquired properties are expected to maintain their operating cost structure of approximately $4.00 per boe and their inclusion should result in a positive impact to our operating costs. While lower power costs continue to benefit our unit operating costs, we anticipate that the impact of continuing cost pressures in the Alberta oil field service sector will be offset somewhat by the economies of scale afforded to larger operators and our efforts to manage costs.

Currently, the forward price curve for the WTI benchmark price exceeds US$75 for the balance of 2006 with the heavy oil differential expected to widen from its current level of less than 30% of the WTI price as we move through the next few months. Our oil price risk management contracts, which include upside participation, provide a floor price of approximately US$45 on 23,750 bbl/day for the balance of 2006 with the estimated forgone revenue estimated to be approximately $6.50 per bbl of oil over the period. As a result, we expect to realize approximately US$68/bbl on our portfolio of crude oil production for the balance of 2006 based on the current forward curve. In respect of natural gas prices, we have the following price risk management positions:

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We have completed a detailed review of our 2006 capital spending program and have added $50 million to the previously announced $250 million capital budget, excluding acquisitions. With capital spending of $157.5 million incurred through June, we have added an additional $25 million in respect of the recently acquired properties plus an incremental $25 million as a result of updating the plans for our existing assets. In addition, we will continue to pursue incremental acquisitions/dispositions/farmouts that focus on increasing our ownership interest in existing assets while disposing of marginal interests in other properties.

We have announced a monthly distribution of $0.38 per trust unit for July, August and September and we continue to expect that provided commodity prices remain at their current levels, our payout ratio is expected to be in the 70% to 80% range for the balance of the year, with monthly distributions at $0.38 per Trust Unit. Currently, we enjoy a participation level in our distribution reinvestment plan in excess of 40% and we will use this source of funding to round out the financing of our capital spending program and direct any surplus to debt reduction.

The following table reflects sensitivities of our expected 2007 Cash Flow, including the effect of our acquisition announced on July 26, 2006 and concurrent equity financing.

As the consolidation/rationalization of the Canadian royalty trust sector continues, we expect to be an active participant in appropriate opportunities; however, the property acquisition market in the western Canadian sedimentary basin continues to be very competitive with a modest supply of attractive opportunities. We also routinely evaluate our property portfolio and dispose of properties that are viewed as having insignificant future development potential. In addition, we intend to maintain a strong balance sheet with significant credit capacity to support a large scale acquisition. With or without further acquisitions, we will continue to develop our existing assets, a very significant resource base.

(1) This is a non-GAAP measure as referred to under "Non-GAAP Measures".

(2) The sum of the interim periods does not equal the total per year amount as there were large fluctuations in the weighted average number of Trust Units outstanding in each individual quarter.

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Cash flows have also steadily risen over the same period, with marked increases in the third quarter of 2005 in which Harvest benefited from higher production from the Hay River acquisition, stronger crude oil prices and narrower heavy oil differentials early in the quarter. However, this trend did not continue into the fourth quarter of 2005 as a result of decreased commodity prices and widening heavy oil differentials, which continued into the first quarter of 2006 and also impacted Cash Flows. In the second quarter of 2006, Cash Flows were positively impacted by higher commodity prices, lower heavy oil differentials and a full quarter of production from the Viking Energy Royalty Trust assets acquired in February of 2006. The most significant increases in revenue occurred through the first and second quarter of 2006, due to unprecedented commodity prices and the impact of the Viking acquisition that occurred in the first quarter. The general increasing revenue trend since the third quarter of 2004 is also attributable to the strong commodity price environment through 2005 and into 2006.

Net income reflects both cash and non-cash items. Changes in non-cash items, including depletion, depreciation and accretion (DD&A) expense, unrealized foreign exchange gains and losses, unrealized gains and losses on risk management contracts, Trust Unit right compensation expense and future income taxes can cause net income to vary significantly from period to period. However, these items do not impact the Cash Flows available for distribution to Unitholders, and therefore we believe net income to be a less meaningful measure of performance for us. The main reason for the volatility in net income (loss) between quarters in 2005 and 2006 is due to the changes in the fair value of our risk management contracts. We ceased using hedge accounting for all of our risk management contracts in October 2004 and switched to a fair value accounting methodology, which has substantially increased the volatility in our reported earnings. Due primarily to the inclusion of unrealized mark-to-market gains and losses on risk management contracts, net income (loss) has not reflected the same trend as net revenues or Cash Flows.

Critical accounting policies and estimates are the same as those presented in our 2005 annual MD&A.

In an effort to harmonize Canadian GAAP with U.S. GAAP, the Canadian Accounting Standards Board has recently issued new Handbook sections:

Under these new standards, all financial assets should be measured at fair value with the exception of loans, receivables and investments that are intended to be held to maturity and certain equity investments, which should be measured at cost. Similarly, all financial liabilities should be measured at fair value when they are either derivatives or held for trading. Gains and losses on financial instruments measured at fair value will be recognized in the income statement in the periods they arise with the exception of gains and losses arising from:

Sections 3855 and 3865 make use of the term "other comprehensive income". Other comprehensive income comprises revenues, expenses, gains and losses that are excluded from net income. Unrealized gains and losses on qualifying hedging instruments, unrealized foreign exchange gains and losses, and unrealized gains and losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Comprehensive income

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and its components will be a required disclosure under the new standard. Section 3861 addresses the presentation of financial instruments and non-financial derivatives, and identifies the information that should be disclosed about them. These standards are effective for interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. As we do not apply hedge accounting to any of our derivative instruments, we do not expect these pronouncements to have a significant impact on our consolidated financial results.

The AcSB has issued Section 3831, Non-Monetary Transactions, which replaces Section 3830, and requires all non-monetary transactions to be measured at fair value unless:

• the transaction lacks commercial substance;

• the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange;

• neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or

• the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation.

The new requirements apply to non-monetary transactions, initiated in periods beginning on or after January 1, 2006. Earlier adoption was permitted as of the beginning of a period beginning on or after July 1, 2005. This section did not have a material impact on our results of operations or financial position.

Our operational and other business risks are substantially the same as those presented in our 2005 annual MD&A.

Throughout this MD&A we have referred to certain measures of financial performance that are not specifically defined under Canadian GAAP. Specifically, we use Cash Flow as cash flow from operating activities before changes in non-cash working capital, settlement of asset retirement obligations and one time transaction costs. Cash Flow as presented is not intended to represent an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with Canadian GAAP. Management uses Cash Flow to analyze operating performance and leverage. Payout Ratio, Cash G&A and Operating Netbacks are additional non-GAAP measures used extensively in the Canadian energy trust sector for comparative purposes. Payout Ratio is the ratio of distributions to total Cash Flow. Operating Netbacks are always reported on a per boe basis, and include gross revenue, royalties and operating expenses, net of any realized gains and losses on related risk managements. Cash G&A are G&A expenses excluding the effect of our unit based compensation plans.

For the three and six months ended June 30, 2006 and 2005, Cash Flows are reconciled to its closest GAAP measure, Cash Flow from operating activities, as follows:

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This MD&A highlights significant business results and statistics from our consolidated financial statements for the three and six months ended June 30, 2006 and the accompanying notes thereto. In the interest of providing our Unitholders and potential investors with information regarding Harvest, including our assessment of our future plans and operations, this MD&A contains forward-looking statements that involve risks and uncertainties. Such risks and uncertainties include, but are not limited to, risks associated with conventional petroleum and natural gas operations; the volatility in commodity prices and currency exchange rates; risks associated with realizing the value of acquisitions; general economic, market and business conditions; changes in environmental legislation and regulations; the availability of sufficient capital from internal and external sources and such other risks and uncertainties described from time to time in our regulatory reports and filings made with securities regulators.

Forward-looking statements in this MD&A include, but are not limited to, production volumes, operating costs, commodity prices, administrative costs, commodity price risk management activity, acquisitions and dispositions, capital spending, distributions, access to credit facilities, capital taxes, income taxes, Cash Flow From Operations and regulatory changes. For this purpose, any statements that are contained herein that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements often contain terms such as "may", "will", "should", "anticipate", "expects", and similar expressions.

Readers are cautioned not to place undue reliance on forward-looking statements as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. Although consider such information reasonable, at the time of preparation, it may prove to be incorrect and actual results may differ materially from those anticipated. We assume no obligation to update forward-looking statements should circumstances or estimates or opinions change except as required by law. Forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

Further information about us, including our Annual Information Form, can be accessed under our public filings found on SEDAR at www.sedar.com or at www.harvestenergy.ca. Information can also be found by contacting our Investor Relations department at (403) 265-1178 or at 1-866-666-1178.

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