Harvest Energy Trust 6K Announces Second Quarter 2007 Financial and Operating Results | HTE 15 Aug 07

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s discussion and analysis ("MD&A") of the financial condition and results of operations of Harvest Energy Trust should be read in conjunction with our audited consolidated financial statements and accompanying notes for the years ended December 31, 2006 and 2005, our MD&A for the year ended December 31, 2006 as well as our interim consolidated financial statements and notes for the three and six month periods ended June 30, 2007 and 2006. The information and opinions concerning our future outlook are based on information available at August 13, 2007.

When reviewing our 2007 results and comparing them to 2006, readers should be cognizant that the 2007 results include six months of operations from our acquisition of Viking Energy Royalty Trust ("Viking") in February 2006, Birchill Energy Ltd. ("Birchill") in August 2006 and North Atlantic Refining Ltd. ("North Atlantic") in October 2006 whereas the comparative results in 2006 include only five months of operations from our acquisition of Viking. This significantly impacts the comparability of our operations and financial results for the three month and six month periods ended June 30, 2007 to the comparative period in the prior year.

In this MD&A, reference to "Harvest", "we", "us" or "our" refers to Harvest Energy Trust and all of its controlled entities on a consolidated basis. All references are to Canadian dollars unless otherwise indicated. Tabular amounts are in thousands of dollars unless otherwise stated. Natural gas volumes are converted to barrels of oil equivalent ("boe") using the ratio of six thousand cubic feet ("6 mcf") of natural gas to one (1) barrel of oil ("bbl"). Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. In accordance with Canadian practice, production volumes, reserve volumes and revenues are reported on a gross basis, before deduction of crown and other royalties, unless otherwise stated.

In this MD&A, we use certain financial reporting measures that are commonly used as benchmarks within the oil and natural gas industry such as Funds From Operations, Earnings From Operations, Payout Ratio, Cash General and Administrative Expenses and Operating Netbacks and with respect to the refining industry, Gross Margin and Operating Income which are each defined in this MD&A including tables with their calculation. 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. Please refer to the discussion under the heading "Non-GAAP Measures" at the end of this MD&A for a detailed discussion of these reporting measures.

Consolidated Financial and Operating Highlights – Second Quarter 2007

Funds From Operations of $244.5 million for the three month period ended June 30, 2007, an increase of $97.5 million over the prior year primarily due to our acquisitions in 2006 and continued strength in oil prices.

North Atlantic’s Funds From Operations of $138.4 million reflects the combined benefits of robust refining margins and solid refinery operating performance as throughput averaged 115,570 bbls/d.

Funds From Operations of our petroleum and natural gas activity totaled $140.9 million with production averaging 60,989 boe/d, a narrowing of oil price differentials and reduced losses on the settlement of price risk management contracts.

Balance sheet bolstered with a $200 million increase to our Three Year Extendible Revolving Credit Facility and the issuance of 7,302,500 Trust Units for net proceeds of $218.5 million while $125.6 million principal amount of convertible debentures were converted to 4,613,915 Trust Units.

On June 8, 2007, we entered into a pre-acquisition agreement to acquire Grand Petroleum Inc. for aggregate consideration of approximately $145 million, an acquisition of approximately 3,400 boe/d of production and proved plus probable (P+P) reserves of 6 million boe, comprised of approximately 67% of oil. In early August 2007, we completed the acquisition and will include these operations with Harvest’s in the Third Quarter.

Maintained our monthly distributions of $0.38 per trust unit through the quarter resulting in a Payout Ratio of 63% and announced the continuation of a $0.38 per trust unit monthly distribution for the third quarter of 2007.

SELECTED INFORMATION

The table below provides a summary of our financial and operating results for the three and six month periods ended June 30, 2007 and 2006. Detailed commentary on individual items within this table is provided elsewhere in this MD&A.

	Three Months Ended June 30					Six Months Ended June 30

($000s except where noted)
		2007		2006	Change		2007		2006	Change

Revenue, net⁽¹⁾		1,137,638		233,128	388%		2,148,732		364,560	489%

Funds From Operations		244,461		147,010	66%		458,402		247,981	85%
Per trust unit, basic	$	1.83	$	1.45	26%	$	3.51	$	2.70	30%
Per trust unit, diluted	$	1.62	$	1.43	13%	$	3.13	$	2.66	18%

Net Income⁽³⁾		6,248		60,682	(90%)		76,098		26,745	185%
Per trust unit, basic	$	0.05	$	0.60	(92%)	$	0.58	$	0.29	100%
Per trust unit, diluted	$	0.05	$	0.60	(92%)	$	0.58	$	0.29	100%

Distributions declared		154,057		115,889	33%		299,327		210,701	42%
Distributions declared, per trust unit	$	1.14	$	1.14	-%	$	2.28	$	2.25	1%
Payout ratio ⁽²⁾		63%		79%	(16%)		65%		85%	(20%)

Bank debt							1,047,965		227,544	361%
Senior debt							258,387		279,050	(7%)
Convertible Debentures							655,396		240,246	173%
Total long-term financial liabilities							1,961,748		746,840	163%

Total assets							5,613,333		3,455,918	62%

PETROLEUM AND NATURAL GAS OPERATIONS
Daily Production
Light to medium oil (bbl/d)		27,586		28,951	(5%)		27,311		26,497	3%
Heavy oil (bbl/d)		14,719		13,037	13%		15,164		14,045	8%
Natural gas liquids (bbl/d)		2,338		2,016	16%		2,417		1,865	30%
Natural gas (mcf/d)		98,078		96,848	1%		99,671		85,158	17%
Total daily sales volumes (boe/d)		60,989		60,145	1%		61,504		56,600	9%

Cash capital expenditures		48,221		54,230	(11%)		196,708		157,469	25%

REFINING AND MARKETING OPERATIONS
Average daily throughput (bbl/d)		115,570		-	n/a		114,646		-	n/a
Aggregate throughput (mbbl)		10,517		-	n/a		20,751		-	n/a

Average Refining Margin (US$/bbl)		15.64		-	n/a		13.69		-	n/a

Cash capital expenditures		9,871		-	n/a		14,754		-	n/a

(1) Revenues are net of royalties and risk management activities

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

(3) Net Income includes a future income tax expense of $177.7 million for the three and six months ended June 30, 2007. Please see Note 14 to the Consolidated Financial Statements for further information.

REVIEW OF SECOND QUARTER PERFORMANCE

Harvest is an integrated energy trust with our petroleum and natural gas business focused on the operation and development of quality properties in western Canada and our refining and marketing business focused on the safe operation of a medium gravity sour crude hydrocracking refinery (the "Refinery") and a petroleum marketing business both located in the province of Newfoundland and Labrador.

In the Second Quarter of 2007, we generated Funds From Operations of $244.5 million ($1.83 per basic trust unit) compared to $147.0 million ($1.45 per basic trust unit) in the second quarter of 2006. This $97.5 million increase is predominantly attributed to the incremental contribution from our North Atlantic acquisition, lower cash settlements on commodity price risk management contracts along with acquisitions in our petroleum and natural gas operations offsetting weakness in natural gas prices and production declines. During the Second Quarter of 2007, our North Atlantic business unit benefited from very strong prices for gasoline and distillate products while our refinery throughput averaged 115,570 bbls/d. During the same period, our petroleum and natural gas operations reflected a softening of production and a widening of the price differentials between western Canadian crudes (Edmonton Par and Bow River) and the West Texas Intermediate ("WTI") benchmark price as compared to the prior year. In addition, the settling of our price risk management contracts resulted in a $6.8 million loss this quarter as the floor price of our oil price contracts averaged US$55.67 compared to a floor price of US$42.11 and a $23.9 million loss in the prior year.

During the Second Quarter of 2007, North Atlantic’s Funds From Operations totaled $138.4 million as compared to $94.7 million in the prior quarter. Our refinery operated at near capacity reporting 115,570 bbls/d of throughput and benefited from a 32% increase in gross margin to US$15.64 per bbl as compared to 113,711 bbls/d of throughput and a gross margin in US$11.85 per bbl in the prior quarter. During the Second Quarter of 2007, the industry benchmark "2-1-1 crack spread" averaged US$22.00, as compared to US$12.31 in the prior quarter, an 79% increase. North Atlantic’s gross margin did not enjoy the full benefit of improving crack spreads as the significant narrowing of the price differential on the medium gravity sour crude oil processed by North Atlantic increased our costs relative to the WTI benchmark price, the cost of our purchased vacuum gas oil increased and our refinery produced approximately 25% heavy fuel oil which is not factored into the "2-1-1 Crack Spread" benchmark. The refinery operating costs were as anticipated.

Production from our petroleum and natural gas operations for the Second Quarter of 2007 was 60,989 boe/d, including three months of production from the assets acquired in the Birchill acquisition of August 2006, as compared to 60,145 boe/d in the Second Quarter of 2006. In 2007, our Second Quarter production is lower than our First Quarter of 62,024 boe/d as increased production from our Hay River capital program and recent acquisitions was more than offset by shortfalls in production attributed to delays in capital programs and well servicing due to an extended wet spring break-up. Further, the prices realized for our production suffered from a softening of the prices for light sweet crude oil as well as from a widening of the differential between the price received for heavy crude oil in western Canada and Edmonton Par price: prices realized on our production were 24% lower for heavy oil and 9% lower for light to medium oil as compared to the Second Quarter of 2006. During the Second Quarter of 2007, our price for natural gas was 15% higher than in the prior year with the year-to-date price 8% higher than in the prior year. Our gross revenues during the Second Quarter of 2007 were 7% lower before the impact of price risk management and royalties while our net revenues after deducting realized price risk management losses were only 2% lower than the prior year. On a year-to-date basis, our gross revenues in 2007 were up 8% before the impact of price risk management and royalties and were 14% higher after deducting realized price risk management losses. In 2007, unit operating costs of $13.13 per boe for the Second Quarter and $13.00 per boe for the year-to-date reflect the impact of the higher than anticipated cost to operate the assets acquired with the Birchill acquisition as well as the increasing cost of operating in western Canada. Overall, our operating netback during the Second Quarter of 2007 was $27.12 per boe compared to $30.81 in the comparative period in 2006 with the year-to-date netback aggregating to $28.44 in 2007 as compared to $28.24 a year earlier.

During the Second Quarter, Harvest bolstered its balance sheet with an issuance of 7,302,500 Trust Units for net proceeds of $218.5 million, an extension of the maturity date of our Three Year Extendible Revolving Credit Facility as well as an increase in the amount of the Facility from $1.4 billion to $1.6 billion. In addition, the trading value of our Trust Units has encouraged $125.6 million of principal amount of convertible debentures to convert into 4,613,915 Trust Units. At the end of June 2007, Harvest’s total debt to total capitalization was 36% and its bank debt to annualized earnings before interest, taxes, depreciation and amortization ("EBITDA") was 2.3 times. Subsequent to the end of June 2007, an additional $35.1 million principal amount of convertible debentures were converted into 1,281,975 Trust Units further enhancing our balance sheet.

On June 11, 2007, Harvest and Grand Petroleum Inc. ("Grand") entered into a pre-acquisition agreement whereby Harvest agreed it would make an offer to purchase all of the outstanding shares of Grand for $3.84 per share in cash subject to there being at least 66^2/3% of the outstanding shares tendered to the offer. The acquisition of Grand represents an aggregate consideration of approximately $145 million consisting of $110 million for the shares of Grand and a further $35 million commitment in respect of the assumption of Grand’s bank debt and estimated working capital deficiency. During the three months ended March 31, 2007, Grand’s production averaged 3,409 boe/d comprised of 2,322 barrels of oil and 6,521 mcf of natural gas with estimated total proved plus probable (P+P) reserves of 6 million boe resulting in acquisition economics of approximately $42,500 per flowing boe and $24 per boe of proved plus probable reserve. In addition, Grand also has 65,000 acres (46,000 net acres) of undeveloped land and supporting seismic. In early August 2007, Harvest completed its acquisition of Grand and will commence including these operations in its results during the Third Quarter of 2007. Harvest will fund this acquisition from its existing $1.6 billion Three Year Extendible Revolving Credit Facility.

Distributions declared during the Second Quarter of 2007 totaled $1.14 per trust unit resulting in our payout ratio being 63% of Funds From Operations compared to $1.14 and 79% (before deducting $0.7 million of cash transaction costs relating to the Viking acquisition) in the prior year. For the Second Quarter of 2007, the participation in our distribution reinvestment plan ("DRIP") was approximately 29% while in the Second Quarter of 2006 the participation rate was approximately 41%. Our DRIP enables us to settle our distributions through the issue of units, allowing us to use the cash to reinvest in our capital program or for debt repayment.

During the Second Quarter of 2007, the Government of Canada enacted Bill C-52 Budget Implementation Act, 2007 ("Bill C-52") which contained the legislative provisions to apply a 31.5% tax on distributions from Canadian publicly traded income trusts. With these provisions enacted, we have recorded a future income tax provision of $177.7 million in our Second Quarter financial results to reflect a 31.5% tax rate on substantially all of the timing differences between the book value and the tax basis of assets held by our mutual fund trust. This is a non-cash item that has no current impact on our cash from operating activities: however, it has resulted in our reporting net income of $6.2 million for the three months ended June 30, 2007 as compared to net income of $60.7 million in the prior year.

Business Segments

As a result of the acquisition of North Atlantic in October of 2006, our business has two segments: petroleum and natural gas in western Canada and refining and marketing in the Province of Newfoundland and Labrador. Our petroleum and natural gas business consists of our production and development activities in western Canada and our refining and marketing business consists of a medium gravity sour crude hydrocracking refinery with a crude oil throughput capacity of 115,000 barrels per day, 61 retail gas stations, 3 cardlock locations as well as wholesale gasoline and home heating businesses. The following table presents selected financial information for our two business segments:

	Three Months Ended June 30				Six Months Ended June 30
		2007		2006		2007		2006
(in $000’s)	Petroleum	Refining	Total	Total⁽³⁾	Petroleum	Refining	Total	Total⁽³⁾
	and natural	and			and natural	and
	gas	marketing			gas	marketing
Revenue⁽¹⁾	240,415	897,223	1,137,638	233,128	467,464	1,681,268	2,148,732	364,560
Earnings From
Operations⁽²⁾	37,200	116,014	153,214	62,449	64,634	191,370	256,004	39,285

Capital expenditures	48,221	9,871	58,092	54,230	196,708	14,754	211,462	157,469
Total assets	3,952,579	1,660,754	5,613,333	3,455,918	3,952,579	1,660,754	5,613,333	3,455,918

(1) Revenues are net of royalties and risk management activities

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

(3) For the three and six month periods ended June 30, 2006, Harvest’s operations consisted of only petroleum and natural gas operations.

PETROLEUM AND NATURAL GAS OPERATIONS

Financial and Operating Results

Throughout the Second Quarter of 2007, our production mix was approximately 49% light to medium oil and natural gas liquids, 24% heavy oil and 27% natural gas with our core areas of production located in Alberta, Saskatchewan and northeastern British Columbia.

The following summarizes the financial and operating information of our petroleum and natural gas operations for the three and six month periods ended June 30, 2007 and 2006:

(in $000’s)	Three Months Ended June 30			Six Months Ended June 30
	2007	2006	Change	2007	2006	Change

Revenues	$ 286,611	$ 309,010	(7%)	$ 577,727	$ 533,285	8%
Royalties	(53,548)	(51,907)	3%	(103,197)	(95,022)	9%
Realized losses on price risk management contracts⁽¹⁾	(6,266)	(24,118)	(74%)	(7,063)	(33,326)	(79%)
Unrealized gains (losses) on price risk management contracts	14,178	(115)	12,429%	57	(41,112)	(100%)
Net revenues excluding realized losses on electric power fixed price contracts	240,975	232,870	3%	467,524	363,825	29%

Operating expenses	72,333	60,593	19%	144,629	110,687	31%
Realized (gains) losses on electric power fixed price contracts	560	(258)	317%	60	(735)	108%
Net operating expenses	72,893	60,335	21%	144,689	109,952	32%

General and administrative expenses	16,061	8,513	89%	26,165	14,325	83%
Transportation and marketing	3,375	4,065	(17%)	6,187	5,688	9%
Transaction costs	-	330	n/a	-	12,072	n/a
Depreciation, depletion, amortization and accretion	111,446	97,178	15%	225,849	182,503	24%

Earnings From Operations⁽²⁾	37,200	62,449	(40%)	64,634	39,285	65%

Cash capital expenditures (excluding acquisitions)	48,221	54,230	(11%)	196,708	157,469	25%
Property and business acquisitions, net of dispositions	(21,801)	290	(7,618%)	9,152	23,672	(61%)

Daily sales volumes
Light to medium oil (bbl/d)	27,586	28,951	(5%)	27,311	26,497	3%
Heavy oil (bbl/d)	14,719	13,037	13%	15,164	14,045	8%
Natural gas liquids (bbl/d)	2,338	2,016	16%	2,417	1,865	30%
Natural gas (mcf/d)	98,078	96,848	1%	99,671	85,158	17%
Total (boe/d)	60,989	60,145	1%	61,504	56,600	9%

(1) Includes amounts realized on WTI, heavy oil price differential and currency exchange contracts and excludes amounts realized on electric power fixed price contracts.

⁽²⁾ These are non-GAAP measures; please refer to "Non-GAAP Measures" in this MD&A.

Commodity Price Environment

	Three Months Ended June 30			Six Months Ended June 30
Benchmarks	2007	2006	Change	2007	2006	Change

West Texas Intermediate crude oil (US$ per barrel)	65.03	70.70	(8%)	61.60	67.09	(8%)
Edmonton light crude oil ($ per barrel)	71.89	78.63	(9%)	69.50	73.80	(6%)
Bow River blend crude oil ($ per barrel)	50.78	60.59	(16%)	50.41	50.28	0%
AECO natural gas daily ($ per mcf)	7.07	6.01	18%	7.23	6.67	8%
AECO natural gas monthly ($ per mcf)	7.37	6.27	18%	7.41	7.77	(5%)

Canadian / U.S. dollar exchange rate	0.911	0.891	2%	0.882	0.878	0%

The West Texas Intermediate ("WTI") crude oil price was 8% lower during the three and six month periods ended June 30, 2007 than in the prior year. The reduction in the average Edmonton light crude oil price ("Edmonton Par") closely mirrors the change in the WTI price as the Canadian/U.S. dollar exchange rate was substantially unchanged during the comparative six month periods and with the three month period ended June 30, 2007 reflecting a modest appreciation of the Canadian dollar over the US dollar over the prior year. The narrowing of the differentials between WTI and Edmonton Par in 2007 has continued with the strong demand for Canadian light crude resulting in an average premium of $0.51 realized for Edmonton Par in the three month period ended June 30, 2007 as compared to a $0.72 discount in the prior year.

For the six month period ended June 30, 2007, prices for heavy crude oil of $50.41 was essentially unchanged from $50.28 in the prior year as the $4.30 reduction in the Edmonton Par price was offset by a narrowing heavy oil differential. Whereas during the three months ended June 30, 2007, the prices for heavy oil were 16% lower than in the prior year as compared to the Edmonton Par price which was 9% lower reflecting an additional $3.07 widening of the heavy oil differential from 22.9% in 2006 to 29.4% in the current year. The heavy oil differential fluctuates based on a combination of factors including the level of heavy oil inventories, pipeline capacity to deliver heavy crude to U.S. markets as well as the seasonal demand for heavy oil. In the Second Quarter of 2007, heavy oil demand was impacted by planned maintenance and unplanned disruptions in U.S. heavy oil refining as well as by a late start to the asphalt paving season in western Canada. Shown below are heavy oil differentials for the last eight quarters.

	2007		2006				2005
Differential Benchmarks	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Bow River Blend differential to Edmonton Par	29.4%	25.4%	30.3%	25.8%	22.9%	42.0%	40.0%	28.2%

Compared to the prior year, natural gas prices during the Second Quarter were 18% higher reflecting the influence of lower natural gas storage inventories in 2007 as well as a lower level of weekly injections.

Realized Commodity Prices

The following table provides our average price realized by product as well as our net realized price before and after realized losses on price risk management contracts for the three and six month periods ended June 30, 2007 and 2006.

	Three Months Ended June 30			Six Months Ended June 30
	2007	2006	Change	2007	2006	Change
Light to medium oil ($/bbl)	59.20	65.30	(9%)	58.93	59.67	(1%)
Heavy oil ($/bbl)	43.27	56.73	(24%)	44.15	45.35	(3%)
Natural gas liquids ($/bbl)	58.67	63.35	(7%)	55.64	60.26	(8%)
Natural gas ($/mcf)	7.57	6.59	15%	7.81	7.23	8%
Average realized price ($/boe)	51.64	56.46	(9%)	51.90	52.06	0%
Realized price risk management losses ($/boe)⁽¹⁾	(1.13)	(4.41)	(74%)	(0.63)	(3.25)	(81%)
Net realized price ($/boe)	50.51	52.05	(3%)	51.27	48.81	5%

(1) Includes amounts realized on WTI, heavy oil price differential and foreign exchange contracts and excludes amounts realized on electric power fixed price contracts.

During the Second Quarter of 2007, our average realized price was 9% lower before the realized losses on our price risk management contracts but only 3% lower after deducting the realized losses on these contracts as compared to the prior year. On a year-to-date basis, our average realized price was essentially unchanged before the realized losses on our price risk management contracts and 5% higher after deducting the realized losses on these contracts as compared to the prior year. As compared to the prior year, the significant reductions in our realized losses on price risk management in 2007 is attributed to the higher contracted floor prices although the lower WTI price in the Second Quarter of 2007 was also a contributing factor.

In the Second Quarter and for the first six months of 2007, the realized price of our light to medium oil sales was 9% and 1% lower than in the comparative period in the prior year while the Edmonton Par price decreased 9% and 6% over the same periods. While the Second Quarter price changes are as expected, the year-to-date change reflects the improved quality differentials realized in the First Quarter of 2007 for our light to medium oil production relative to the Edmonton Par benchmark price as the primary reason for our higher than expected realized price.

During the Second Quarter of 2007, the realized price on our heavy oil production was 24% lower than in the prior year compared to a 16% reduction in the Bow River price reflecting the relatively heavier gravity of our recent heavy oil acquisitions in December 2006 and March 2007, as well as a lower price for the sale of this production at the wellhead. The majority of our heavy oil sales are priced off of the Bow River benchmark price. On a year-to-date basis, the realized price for our heavy oil production was 3% lower than for the first six months in the prior year as compared to a relatively unchanged price for the Bow River benchmark price for much the same reasons.

During the Second Quarter of 2007, the realized price for our natural gas production was 15% higher than in the prior year as compared to an 18% increase in the benchmark AECO prices and for the year-to-date prices, our realized price is 8% higher than in the prior year as compared to an 8% increase in the benchmark AECO price for daily pricing. Typically, we sell approximately 60% of our natural gas sales priced off the AECO daily benchmark, approximately 30% sold off the AECO monthly benchmark with the remainder sold to aggregators.

Sales Volumes

The average daily sales volumes by product were as follows:

	Three Months Ended
	June 30, 2007		March 31, 2007
	Volume	Weighting	Volume	Weighting	% Volume Change
Light to medium oil (bbl/d)⁽¹⁾	27,586	45%	27,034	44%	2%
Heavy oil (bbl/d)	14,719	24%	15,614	25%	(6%)
Total oil (bbl/d)	42,305	69%	42,648	69%	(1%)
Natural gas liquids (bbl/d)	2,338	4%	2,496	4%	(6%)
Total liquids (bbl/d)	44,643	73%	45,144	73%	(1%)
Natural gas (mcf/d)	98,078	27%	101,282	27%	(3%)
Total oil equivalent (boe/d)	60,989	100%	62,024	100%	(2%)


	Six Months Ended June 30
	2007		2006
	Volume	Weighting	Volume	Weighting	% Volume Change
Light to medium oil (bbl/d)⁽¹⁾	27,311	44%	26,497	47%	3%
Heavy oil (bbl/d)	15,164	25%	14,045	25%	8%
Total oil (bbl/d)	42,475	69%	40,542	72%	5%
Natural gas liquids (bbl/d)	2,417	4%	1,865	3%	30%
Total liquids (bbl/d)	44,892	73%	42,407	75%	6%
Natural gas (mcf/d)	99,671	27%	85,158	25%	17%
Total oil equivalent (boe/d)	61,504	100%	56,600	100%	9%

(1) Harvest classifies our oil production, except that produced from Hay River, as light to medium and heavy according to NI 51-101 guidance. The oil produced from Hay River has an average API of 24^o (medium grade) and is classified as a light to medium oil, however, it benefits from a heavy oil royalty regime and therefore would be classified as heavy oil according to NI 51-101.

For the three month period ended June 30, 2007, average production was 2% lower than in the prior quarter as reduced volumes of heavy oil and natural gas more than offset the 2% increase in light to medium oil. Had we compared our Second Quarter production with the prior year, much of the increases would be attributed to the acquisition of Birchill in the Third Quarter of 2006 as well as two small heavy oil acquisitions in December 2006 and March 2007.

Light to medium oil production in the Second Quarter of 2007 is 552 bbl/d higher as compared to the immediately prior quarter primarily due to approximately 1,200 bbl/d of the incremental production from the Hay River area offset by modest shortfalls in other areas, attributed to delays in well servicing due to extended wet weather conditions. The Hay River area benefited from a successful acceleration of its capital program overlapping the Fourth Quarter of 2006 and the First Quarter of 2007. Second Quarter Hay River production included production from new wells and a return to normal operations after significant capital activity and routine maintenance turnarounds disrupted production in the First Quarter. Access to the Hay River area is limited to winter only and requires drilling and extensive well servicing to be concentrated during this period. In 2007, our Hay River production averaged 5,451 bbl/d in the First Quarter and 6,719 bbl/d during the Second Quarter. The more significant production shortfalls were in our Red Earth and southeast Saskatchewan areas where well servicing and new well tie-ins were delayed due to extended wet weather conditions and in Markerville where production was curtailed due to maintenance turnarounds at third party processing facilities. Year-to-date, our light to medium oil production is up 814 bbl/d primarily due to the current year including an extra month of production from the Viking acquisition completed in February 2006.

During the Second Quarter of 2007, our heavy oil production was 895 bbl/d lower than in the First Quarter primarily due to wet spring weather conditions impacting our operations at Suffield and Hayter as soft road conditions limited the movement of well servicing equipment. As well, extended "military lockouts" also reduced production at Suffield during the Second Quarter where our operations are located on a Canadian Forces Base. At our heavy oil operations in the Hayter area, production was ahead of the prior year, and our capital program for this area is planned to be executed in the Third Quarter.

Natural gas production in the Second Quarter continues to lag behind our expectations despite the addition of approximately 2,900 mcf/d from a recent discovery at Cairo in west central Alberta. We had expected significant growth in our natural gas production as compared to the prior year primarily due to the acquisition of Birchill in August 2006. This acquisition added approximately 16,500 mcf/d of incremental natural gas production at that time, but has experienced higher than anticipated decline. As well, maintenance turnarounds at third party gas processing facilities severely impacted our natural gas production during the Second Quarter of 2007. For the balance of 2007, our natural gas focus will be limited to achieving better than average production from existing assets and expediting the tie-in of wells drilled in late 2006.

Revenues
		Three Months Ended June 30

(000s)		2007		2006	Change
Light to medium oil sales	$	148,619	$	172,043	(14%)
Heavy oil sales		57,952		67,300	(14%)
Natural gas sales		67,563		58,045	16%
Natural gas liquids sales and other		12,477		11,622	7%
Total sales revenue		286,611		309,010	(7%)
Realized risk management contract losses⁽¹⁾		(6,266)		(24,118)	(74%)

Total revenues including realized risk management contract losses		280,345		284,892	(2%)
Realized (losses) / gains on electric power price risk management contracts		(560)		258	(317%)
Unrealized gains / (losses) on price risk management contracts		14,178		(115)	12,429%
Net Revenues, before royalties		293,963		285,035	3%
Royalties		(53,548)		(51,907)	3%
Net Revenues	$	240,415	$	233,128	3%

		Six Months Ended June 30

(000s)		2007		2006	Change
Light to medium oil sales	$	291,290	$	286,166	2%
Heavy oil sales		121,170		115,287	5%
Natural gas sales		140,933		111,489	26%
Natural gas liquids sales and other		24,334		20,343	20%
Total sales revenue		577,727		533,285	8%
Realized risk management contract losses⁽¹⁾		(7,063)		(33,326)	(79%)

Total revenues including realized risk management contract losses		570,664		499,959	14%
Realized gains on electric power price risk management contracts		(60)		735	(108%)
Unrealized losses on price risk management contracts		57		(41,112)	100%
Net Revenues, before royalties		570,661		459,582	24%
Royalties		(103,197)		(95,022)	9%
Net Revenues	$	467,464	$	364,560	28%

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

Our revenue is impacted by changes to production volumes, commodity prices, and currency exchange rates. During the Second Quarter of 2007, total sales revenue of $286.6 million was $22.4 million lower than in the prior year, of which $26.7 million is attributed to lower realized prices and is offset by $4.3 million in higher volumes. Year-to-date, total sales revenues were $577.7 million, an increase of $44.4 million over the prior year with $46.1 million of the increase attributed to increased volume primarily due to the acquisition of Birchill in August of 2006 and the acquisition of Viking in February 2006.

Light to medium oil sales revenue for the three month period ended June 30, 2007 was $23.4 million lower than in the comparative period, comprised of a $15.3 million unfavourable price variance resulting from the 9% reduction in the realized price coupled with an $8.1 million unfavourable volume variance. The unfavourable volume variance over the prior year is primarily due to the delays in well servicing as a result of extended wet weather conditions in 2007. The year-to-date light to medium oil sales revenues have increased over the prior year by $5.1 million with the impact of incremental volume from the acquisition of Birchill and Viking in 2006 substantially offset by a modest reduction in the realized price and the unfavourable volume variance in the Second Quarter of 2007.

During the Second Quarter of 2007, our heavy oil sales revenue of $58.0 million was $9.3 million lower than in the prior year comprised of an $18.0 million unfavourable price variance somewhat offset by a $8.7 million favourable volume variance as the recent acquisitions of heavy oil properties and the incremental production from recent drilling have more than offset the production shortfalls at Suffield and Hayter. Year-to-date, our heavy oil revenues are $5.9 million higher than in the six months ended June 30, 2006 as a $9.2 million favourable volume variance (again with recent acquisitions and incremental production more than offsetting shortfalls) is somewhat offset by a $3.3 million unfavourable reduction in the price realized on our heavy oil production.

Natural gas sales revenue increased by $9.5 million for the three months ended June 30, 2007 over the prior year primarily due to an $8.7 million favourable price variance coupled with a modest $800,000 favourable volume variance. Year-to-date, natural gas sales revenues are $29.4 million higher than in the first six months of 2006 with a $0.58 per mcf price increase accounting for a $10.5 million favourable variance coupled with a $18.9 million favourable volume variance primarily attributed to the incremental natural gas production for the acquisition of Birchill in August of 2006 and Viking in February of 2006.

During the Second Quarter of 2007, our natural gas liquids and other sales revenue increased by $855,000 compared to the prior year while year-to-date, our revenues increased by $4.0 million. During the Second Quarter of 2007, the increased revenues is the net result of a $1.9 million favourable volume variance being offset by lower realized prices as compared to the year-to-date increase being comprised of a $6.0 million favourable volume variance offset by a $2.0 million reduction attributed to lower realized prices in 2007. Generally, the natural gas liquids volume variance will be aligned with our production of natural gas while the price variances will be aligned with the prices realized for our oil production.

Price Risk Management

Details of our price risk management contracts outstanding at June 30, 2007 are included in Note 16 of our interim consolidated financial statements for the three and six month periods ended June 30, 2007 filed on SEDAR at www.sedar.com. Subsequent to acquiring North Atlantic, Harvest’s participation in the crude oil value chain was extended to include the price of refined products produced by North Atlantic, principally gasoline, distillates (which encompasses low sulphur diesel fuel, jet fuel and heating oil) and heavy fuel oil. This results in our price protection of future cash flows including price protection on refined products and during the Second Quarter of 2007, we commenced contracting our oil price risk management contracts based on refined product pricing. For purposes of this MD&A and the segmented reporting in Note 17 of our financial statements, our price risk management contracts are presented as either relating to our petroleum and natural gas operations or our refining and marketing operations according to the price exposure that is being managed. For refined product price contracts, North Atlantic has entered into inter-company contracts with our petroleum and natural gas operation to shift the WTI price protection to our petroleum and natural gas operations.

The table below provides a summary of net gains and losses on our price risk management contracts for both the three and six month periods ended June 30, 2007 and 2006:

	Three Months Ended June 30
	2007											2006
(000s)		Oil		Gas	Currency		Electricity			Total		Total

Realized (losses) / gains on price risk management contracts	$	(7,043)	$	130	$	647	$	(560)	$	(6,826)	$	(23,860)
Unrealized (losses) / gains on price risk management contracts		872		7,355		9,703		1,735		19,665		(148)
Amortization of deferred gains relating to risk management contracts		-		-		-		-		-		33
Total (losses) / gains on third party risk management contracts	$	(6,171)	$	7,485	$	10,350	$	1,175	$	12,839	$	(23,975)
Unrealized loss on WTI portion of refined product price risk management contracts		(5,487)		-		-		-		(5,487)		-
Total (losses) / gains on price risk management contracts	$	(11,658)	$	7,485	$	10,350	$	1,175	$	7,352	$	(23,975)

	Six Months Ended June 30
	2007											2006
(000s)		Oil		Gas	Currency		Electricity			Total		Total

Realized (losses) / gains on price risk management contracts	$	(6,753)	$	291	$	(601)	$	(60)	$	(7,123)	$	(32,591)
Unrealized (losses) / gains on price risk management contracts		(11,368)		4,539		11,065		1,308		5,544		(41,445)
Amortization of deferred gains relating to risk management contracts		-		-		-		-		-		333
Total (losses) / gains on third party risk management contracts	$	(18,121)	$	4,830	$	10,464	$	1,248	$	(1,579)	$	(73,703)
Unrealized losses on WTI portion of refined product price risk management contracts		(5,487)		-		-		-		(5,487)		-
Total (losses) / gains on price risk management contracts	$	(23,608)	$	4,830	$	10,464	$	1,248	$	(7,066)	$	(73,703)

During the three months ended June 30, 2007, our realized net loss on commodity price risk management contracts related to our petroleum and natural gas operations was $6.8 million as compared to a loss of $23.9 million in the Second Quarter of 2006. Year-to-date, our petroleum and natural gas price risk management program has realized a net loss of $7.1 million as compared to losses of $32.6 million during the first six months of 2006. The principal difference between 2007 and 2006 is the significant reduction in the losses on crude oil price contracts as the floor price on these participating contracts has increased from an average of US$42.11 in 2006 to an average of US$55.67 in 2007. In both 2007 and the prior year, the results of our natural gas price, currency exchange rate and electricity price contracts did not result in either a material gain or loss.

For the three months ended June 30, 2007, our oil price contracts realized losses of $7.0 million as compared to a gain of $290,000 during the First Quarter of 2007 and losses of $26.9 million in the three months ended June 30, 2006. During the Second Quarter of 2007, we had WTI price risk management contracts on 30,000 bbl/d with downside protection at an average floor price of US $55.67 per bbl and 73% participation in prices over US $55.67 as compared to 26,250 bbl/d contracted with downside protection at an average floor price of US$42.11 and 59% participation in prices above US$42.11 in the prior year. As compared to 2006, the WTI price during the Second Quarter of 2007 averaged US$65.03, a decrease of US$5.67 from US$70.70 in the prior year. The reduction of our losses on oil price risk management contracts in 2007 is the result of the higher contracted floor prices and to a lesser extent, lower WTI prices.

During the Second Quarter of 2007, North Atlantic entered into price risk management contracts with respect to an aggregate of 20,000 bbl/d of NYMEX heating oil and Platts fuel oil for the period from January 2008 through December 2008 and concurrently entered into the following inter-company contracts to shift the WTI price protection to our petroleum and natural gas operations:

Quantity	Contract Type	Contracted Price
4,000 bbls/d	Price Collar	Price Floor – US$66.00 and Price Cap – US$75.79
16,000 bbls/d	3 Way Structure	If WTI price is over US$79.57, price received is US$79.57
		If WTI price is between US$79.57 and $67.03, price received is market price
		If WTI price is between US$67.03 and US$52.33, price received is US$67.03
		If WTI price is under US$52.33, price received is market price plus US$14.70

During the Second Quarter of 2007, these are the inter-company WTI contracts that have given rise to the $5.5 million unrealized loss for the petroleum and natural gas operations while providing a $5.5 million unrealized gain for North Atlantic.

During the First Quarter of 2007, we entered into the following two natural gas price risk management contracts to protect our cash flows in the event of soft natural gas prices in the summer of 2007:

Quantity	Term	Contracted Price
20,000 GJ/d	April 2007 – March 2008	If AECO price is below $5.00, price received is market price plus $2.00
		If AECO price is between $5.00 and $7.00, price received is $7.00
		If AECO price is between $7.00 and $10.25, price received is market price.
		If AECO price is over $10.25, price received is $10.25
10,000 GJ/d	April 2007 – March 2008	If AECO price is below $5.00, price received is market price plus $2.00
		If AECO price is between $5.00 and $7.00, price received is $7.00
		If AECO price is between $7.00 and $10.30, price received is market price.
		If AECO price is over $10.30, price received is $10.30

During the Second Quarter of 2007, we realized a gain of $130,000 as these contracts settled and in July of 2007, we entered into contracts to unwind these positions and collected net proceeds of $5.5 million that will be reflected as realized gains of $2.5 million, $2.1 million and $900,000 in the Third and Fourth Quarters of 2007 as well as the First Quarter of 2008, respectively being the respective periods to which the gains relate. Currently, we do not have any natural gas price risk management contracts in place.

During the First and Second Quarters of 2007, we had currency exchange rate contracts in place on US$8,750,000 per month at a fixed rate of approximately $0.89 which resulted in $1.2 million of loss and a $647,000 gain, respectively, as the exchange rate averaged approximately $0.85 during the First Quarter and approximately $0.91 during the Second Quarter. For the balance of 2007, we have contracts that fix the currency exchange rate on US$8,750,000 per month at an average rate of approximately $0.89. In addition, we have benefited from our U.S. dollar denominated debt, both the 7 7/8% Senior Notes and U.S. dollar denominated bank borrowings as we have accumulated a significant decrease in the Canadian dollar equivalent as the Canadian dollar appreciates against the U.S. dollar. However, the majority of this gain is currently unrealized which is not included in Funds from Operations.

During the Second Quarter of 2007, our electric power price risk management contracts realized a loss of $560,000 as compared to a gain of $500,000 in the First Quarter of 2007 and a gain of $258,000 in the Second Quarter of the prior year. We enter into these contracts to provide protection from rising electric power prices. During the Second Quarter of 2007, Alberta’s electric power price averaged $49.97 per megawatt hour ("MWh") as compared to our contracted price of $56.69 per MWh. Additional details on these contracts is provided under the heading "Operating Expenses" of this MD&A.

During the Second Quarter of 2007, we recorded a net unrealized gain on our petroleum and natural gas price risk management contracts of $14.2 million comprised of gains on our natural gas, currency exchange rate and electricity price contracts of $18.8 million offset by unrealized losses of $4.6 million on our WTI price contracts including the inter-company contracts with North Atlantic. At June 30, 2007, our price risk management contracts, including the North Atlantic refined product contracts, had an unrealized mark-to-market deficiency of $5.0 million as compared to a mark-to-market deficiency of $1.9 million at December 31, 2006.

Royalties

We pay Crown, freehold and overriding royalties to the owners of mineral rights from which production is generated. These royalties vary for each property and product and our Crown royalties are based on a sliding scale dependent on production volumes and commodity prices.

For the three and six months ended June 30, 2007, our net royalties as a percentage of gross revenue were 18.7% (16.8% - three months ended June 30, 2006) and 17.9% (17.8% - six months ended June 30, 2006) respectively and aggregated to $53.5 million ($51.9 million – three months ended June 30, 2006) and $103.2 million ($95.0 million – six months ended June 30, 2006). Our year to date net royalties as a percentage of gross revenue are in line with our expectations given our current mix of properties, while the second quarter royalty rate is slightly higher due to additional crown royalties assessed by the B.C. government on our Hay River properties.

Operating Expenses
	Three Months Ended June 30
									Per BOE
($000s)		2007	Per BOE			2006		Per BOE	Change
Operating expense
Power	$	11,368	$	2.05	$	12,227	$	2.23	(8%)
Workovers		14,856		2.68		12,843		2.35	14%
Repairs and maintenance		16,115		2.90		7,317		1.34	116%
Labour – internal		3,536		0.64		5,912		1.08	(41%)
Processing fees		8,387		1.51		4,774		0.87	74%
Fuel		2,710		0.49		2,382		0.44	11%
Labour – external		3,835		0.69		3,541		0.65	6%
Land leases and property tax		5,406		0.97		3,781		0.69	41%
Other		6,120		1.10		7,816		1.42	(23%)
Total operating expense		72,333		13.03		60,593		11.07	18%
Realized (gains)/loss on electric power price risk management contracts		560		0.10		(258)		(0.05)	300%
Net operating expense	$	72,893	$	13.13	$	60,335	$	11.02	19%

Transportation and marketing expense	$	3,375	$	0.61	$	4,065	$	0.74	(18%)


	Six Months Ended June 30
									Per BOE
($000s)		2007	Per BOE			2006		Per BOE	Change
Operating expense
Power	$	25,140	$	2.26	$	24,255	$	2.37	(5%)
Workovers		32,019		2.88		22,189		2.17	33%
Repairs and maintenance		29,749		2.67		11,945		1.17	128%
Labour – internal		7,154		0.64		9,845		0.96	(33%)
Processing fees		16,554		1.49		9,103		0.89	67%
Fuel		4,640		0.42		4,411		0.43	(2%)
Labour – external		7,795		0.70		6,536		0.64	9%
Land leases and property tax		8,532		0.77		8,353		0.81	(6%)
Other		13,046		1.16		14,050		1.36	(15%)
Total operating expense		144,629		12.99		110,687		10.80	20%
Realized (gains)/loss on electric power price risk management contracts		60		0.01		(735)		(0.07)	114%
Net operating expense	$	144,689	$	13.00	$	109,952	$	10.73	21%

Transportation and marketing expense	$	6,187	$	0.56	$	5,688	$	0.56	-%

Total operating expense increased by $11.7 million and $33.9 million respectively for the three and six month periods ended June 30, 2007 compared to the same periods in the prior year. A significant portion of this increase is attributed to the additional production from the incremental activity associated with the assets acquired in the Birchill acquisition completed in August 2006. However, the continued high demand for oilfield services has lead to higher costs for well servicing, workovers, labour and well maintenance. We are beginning to see evidence of service costs decreasing, which should translate to lower per unit operating costs in the coming quarters.

On a per barrel basis our operating costs have increased to $13.03 and $12.99 respectively for the three and six month periods ended June 30, 2007, which represents an 18% and 20% increase over the same periods in the prior year. In addition to the general upward cost pressures in the industry, there was a significant amount of well maintenance and workovers completed in the first and second quarters of 2007 as compared to the prior year. The increased processing fees is directly related to our greater proportion of non-operated properties as a result of the acquisitions of Viking and Birchill. Generally, we incur higher processing fees on non-operated properties as although we own an interest in the well, we may not own an interest in the processing plant and are usually charged a fee for processing which is higher than the per unit cost of operating the facility.

Our transportation and marketing expense was $3.4 million or $0.61 per boe and $6.2 million or $0.56 per boe respectively for the three and six month periods ended June 30, 2007. This represents a 17% decrease and 9% increase in aggregate transportation and marketing expense for the three and six month periods ended June 30, 2007 compared to the same periods in the prior year. However, on a per barrel basis these costs have decreased 18% for the three month period ended June 30, 2007 and have remained constant for the six month period ended June 30, 2007 compared to the same periods in the prior year. These costs relate primarily to delivery of natural gas to Alberta’s natural gas sales hub, the AECO Storage Hub, and to a lesser extent, our costs of trucking clean crude oil to pipeline receipt points. As compared to the prior year, our natural gas production in the second quarter of 2007 is 1% higher and the production for the first half of 2007 is 17% higher. This increase in natural gas production is mainly due to the incremental natural gas production associated with our acquisition of Viking and Birchill in 2006 and contributes to the higher transportations costs. In addition, we changed our relationship with the pipeline operators such that the transportation commitments are now a direct responsibility of Harvest rather than the independent marketer of our production in late 2006.

Electric power costs represented approximately 16% and 17% of our total operating costs during the three and six month periods ended June 30, 2007. Electric power prices per MWh for the three and six month periods ended June 30, 2007 were 7% lower and 3% higher than in the comparative periods, contributing to the 7% decrease in aggregate power costs to $11.4 million in the current quarter and a 4% increase to $25.1 million for the year to date compared to the same periods in the prior year. On a per barrel basis, lower consumption and a 1% and 9% increase in production for the three and six month periods ended June 30, 2007 resulted in a 8% and 5% decrease in electric power costs per boe respectively compared to the same periods in the prior year. Our electric power price risk management contracts resulted in a loss of $560,000 and a loss of $60,000 for the three and six month periods ended June 30, 2007, compared to gains of $258,000 and $735,000 in the same periods in the prior year, respectively. The following table details the electric power costs per boe before and after the impact of our price risk management program.

	Three Months Ended June 30						Six Months Ended June 30
(per boe)		2007		2006	Change		2007		2006	Change
Electric power costs	$	2.05	$	2.23	(8%)	$	2.26	$	2.37	(5%)
Realized loss/(gains) on electricity risk management contracts		0.10		(0.05)	300%		0.01		(0.07)	114%
Net electric power costs	$	2.15	$	2.18	(1%)	$	2.27	$	2.30	(1%)
Alberta Power Pool electricity price (per MWh)	$	49.97	$	53.59	(7%)	$	56.80	$	55.17	3%

Approximately 52% of our estimated Alberta electricity usage is protected by fixed price purchase contracts at an average price of $56.69 per MWh through December 2008. These contracts will moderate the impact of future price swings in electric power as will capital projects undertaken that contribute to improving our efficient use of electric power.

Operating Netback

	Three Months Ended June 30				Six Months Ended June 30
(per boe)		2007		2006		2007		2006
Revenues	$	51.64	$	56.46	$	51.90	$	52.06
Realized loss on risk management contracts⁽¹⁾		(1.13)		(4.41)		(0.63)		(3.25)
Royalties		(9.65)		(9.48)		(9.27)		(9.28)
Operating expense⁽²⁾		(13.13)		(11.02)		(13.00)		(10.73)
Transportation and marketing expense		(0.61)		(0.74)		(0.56)		(0.56)
Operating netback⁽³⁾	$	27.12	$	30.81	$	28.44	$	28.24

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

(2) Includes realized (losses)/gains on electric power price risk management contracts of $(0.10) per boe and $0.05 per boe for the three month periods ended June 30, 2007 and 2006 and $(0.01) per boe and $0.07 per boe for the six month periods ended June 30, 2007 and 2006.

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

Our operating netback represents the net amount realized from our production on a per boe basis after deducting the directly related costs. For the three and six month periods ended June 30, 2007, our operating netback decreased $3.69 per boe (or 12%) to $27.12 and increased $0.20 per boe (or 1%) to $28.44 respectively. The decrease in the three months ended June 30, 2007 compared to the same period in the prior year is due to lower oil prices resulting in a decrease of $4.82 per boe in our realized price, an increase of $2.11 per boe in operating costs, lower losses realized on our price risk management program of $3.28 per boe and marginally lower transportation costs and marginally higher royalties. The small increase in the operating netback for the six months ended June 30, 2007 is due to a decrease in realized price of $0.16 per boe and a $2.27 increase in operating costs that were offset by a $2.62 decrease in the realized loss on price risk management contracts.

General and Administrative ("G&A") Expense

	Three Months Ended June 30						Six Months Ended June 30

(000s except per boe)		2007		2006	Change		2007		2006	Change
Cash G&A⁽¹⁾	$	8,512	$	7,756	10%	$	15,717	$	13,809	14%
Unit based compensation expense		7,549		757	897%		10,448		516	1,925%
Total G&A	$	16,061	$	8,513	89%	$	26,165	$	14,325	83%

Cash G&A per boe ($/boe)	$	1.53		1.42	8%	$	1.41		1.35	4%

(1) Cash G&A excludes the impact of our unit based compensation expense and for the three and six months ended June 30, 2006 of nil and $3.1 million, respectively, of one time transaction costs.

For the three months ended June 30, 2007, Cash G&A costs increased by $0.8 million (or 10%) compared to the same period in 2006. This increase is mainly related to salaries, which is attributed largely to increased staffing levels from our acquisition of Birchill in August 2006. Approximately 75% of our Cash G&A expenses are related to salaries and other employee related costs, while in the prior year only 66% of our Cash G&A was staffing related. Generally, costs to retain technically qualified staff in the western Canadian petroleum and natural gas industry continue to rise.

Our unit based compensation plans provide the employee with the option of settling outstanding awards with cash. As a result, our unit based compensation expense is determined using the intrinsic method being the difference between the trust unit trading price and the strike price of the unit appreciation rights ("UAR") adjusted for the proportion that is vested. Our total unit based compensation expense for the three month period ended June 30, 2007 was $7.5 million. Our opening trust unit market price was $28.57 at March 31, 2007 and at June 30, 2007, our trust unit price had increased to $32.95. As a result, we have recorded an expense of $6.2 million on unexercised UARs for the three month period ended June 30, 2007. Our total unit based compensation expense has increased $6.8 million for the three month period ended June 30, 2007 and $9.9 million for the six month period ended June 30, 2007 over the same period in the prior year after considering that $0.3 million of unit based compensation expense incurred in the three month period ended June 30, 2006 and $9.0 million in the six month period ended June 30, 2006 was recorded as transaction costs. In 2006, we have recorded transaction costs of $11.7 million which represent one time costs incurred by Harvest as part of the acquisition of Viking in respect of Harvest’s outstanding UARs vesting on February 3, 2006 and severance payments made to Harvest employees upon merging with Viking.

Depletion, Depreciation, Amortization and Accretion Expense

		Three Months Ended June 30					Six Months Ended June 30
(000s except per boe)		2007		2006	Change		2007		2006	Change
Depletion, depreciation and amortization	$	103,034	$	88,886	16%	$	208,930	$	166,281	26%
Depletion of capitalized asset retirement costs		3,939		4,230	(7%)		8,000		8,512	(6%)
Accretion on asset retirement obligation		4,473		4,062	10%		8,919		7,710	16%
Total depletion, depreciation, amortization and accretion	$	111,446	$	97,178	15%	$	225,849	$	182,503	24%
Per boe ($/boe)	$	20.08	$	17.76	13%	$	20.29	$	17.81	14%

Our overall depletion, depreciation, amortization and accretion ("DDA&A") expense for the three and six months ended June 30, 2007 was $14.3 million and $43.3 million higher, respectively, compared to the prior year. Of this, $1.4 million and $15.8 million respectively is due to incremental production predominantly from the merger with Viking in early 2006 and the acquisition of Birchill in August of 2006. The remaining increase is attributed to a higher depletion rate per boe, as our acquisitions in 2006 coupled with generally higher finding and development costs have increased our overall corporate DDA&A rate.

Capital Expenditures
	Three Months Ended June 30				Six Months Ended June 30
(000s)		2007		2006		2007		2006
Land and undeveloped lease rentals	$	261	$	326	$	421	$	2,413
Geological and geophysical		1,710		2,027		5,724		3,027
Drilling and completion		16,396		17,955		94,990		84,861
Well equipment, pipelines and facilities		27,806		25,662		91,151		55,546
Capitalized G&A expenses		2,208		3,430		4,451		6,981
Furniture, leaseholds and office equipment		(160)		4,830		(29)		4,641
Development capital expenditures excluding acquisitions and non-cash items		48,221		54,230		196,708		157,469
Non-cash capital additions (recoveries)		1,680		(563)		2,095		(173)
Total development capital expenditures excluding acquisitions	$	49,901	$	53,667	$	198,803	$	157,296

During the second quarter of 2007 we invested $48.2 million in drilling, operating optimization and enhancement projects compared to $54.2 million in the second quarter of 2006. Approximately 34% of the second quarter expenditures were directly related to the drilling of 14 gross wells with a success rate of 100% as compared to 37 gross wells in the second quarter of 2006 with a success rate of 100%. With strong oil prices, we continued to focus our drilling activity on oil opportunities with 11 of the 14 wells drilled targeting oil prospects. Our most active drilling area in the second quarter was Southeast Saskatchewan, where we continued to drill horizontal wells into our new light oil discovery at Kenosee as well as infill horizontal wells at Hazelwood.

After our intensive drilling program in the first quarter, many of the capital expenditures in the second quarter relate to the equipment and facilities that were needed to bring those wells on production; approximately $27.8 million or 58% of the second quarter expenditures relate to well equipment, pipelines and facilities expenditures. This amount also includes approximately $20 million relating to a number of initiatives to improve the efficiency of our Hay River operations.

The following summarizes Harvest’s participation in gross and net wells drilled during the second quarter of 2007:

The following summarizes Harvest’s participation in gross and net wells drilled during the second quarter of 2007:

	Total Wells		Successful Wells		Abandoned Wells
Area	Gross¹	Net	Gross	Net	Gross	Net

Hay River	-	-	-	-	-	-
Southeast Saskatchewan	4.0	4.0	4.0	4.0
Red Earth	-	-	-	-	-	-
Suffield	3.0	3.0	3.0	3.0	-	-
Lloydminster	2.0	2.0	2.0	2.0	-	-
Markerville	-	-	-	-	-	-
Other Areas	5.0	4.3	5.0	4.3	-	-
Total	14.0	13.3	14.0	13.3	-	-
⁽¹⁾ Excludes 6 additional wells that we have an overriding royalty interest in.

The following summarizes Harvest’s participation in gross and net wells drilled for the six months ended June 30, 2007:

	Total Wells		Successful Wells		Abandoned Wells
Area	Gross¹	Net	Gross	Net	Gross	Net

Hay River	31.0	31.0	31.0	31.0	-	-
Southeast Saskatchewan	15.0	15.0	15.0	15.0	-	-
Red Earth	12.0	8.5	12.0	8.5	-	-
Suffield	8.0	8.0	7.0	7.0	1.0	1.0
Lloydminster	8.0	8.0	8.0	8.0	-	-
Markerville	5.0	1.9	5.0	1.9	-	-
Other Areas	27.0	14.0	25.0	13.4	2.0	0.6
Total	106.0	86.4	103.0	84.8	3.0	1.6
⁽¹⁾ Excludes 12 additional wells that we have an overriding royalty interest in.

Corporate Acquisitions

Effective March 1, 2007 we acquired a private petroleum and natural gas corporation for cash consideration of $30.3 million including $350,000 of estimated acquisition costs. This acquisition added approximately 1,500 bbl/d of western Saskatchewan heavy oil production which is immediately adjacent to our existing operations in the area.

On June 11, 2007 we entered into a pre-acquisition agreement to acquire Grand for aggregate consideration of approximately $145 million and in early August 2007 we completed this acquisition of approximately 3,400 boe/d of production with proved plus probable (P+P) reserves of 6 million boe, comprised of approximately 67% oil. Grand’s assets include a significant presence in southeast Saskatchewan, the Sylvan Lake/Markerville area and eastern Alberta which are adjacent to existing Harvest operations with complimentary drilling opportunities. Grand also has 65,000 acres (46,000 net acres) of undeveloped land with supporting seismic data providing further development opportunities. This acquisition represents an acquisition cost of approximately $42,500 per flowing boe and $24 per boe of proved and probable reserves.

Goodwill

Goodwill is recorded when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of that acquired business. At December 31, 2006, we had recorded $656.2 million of goodwill related to our petroleum and natural gas segment and this amount is unchanged at June 30, 2007. 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. To date, no charge for impairment of this goodwill has been made.

Asset Retirement Obligation ("ARO")

In connection with a property acquisition or development expenditures, 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 is adjusted at the end of each period to reflect the passage of time as well as for changes in the estimated future cash flows of the underlying obligation. Our asset retirement obligation increased by $2.5 million during the three months ended June 30, 2007. This increase is due to additions resulting from drilling activity during the quarter and accretion expense, offset by actual asset retirement expenditures made during the quarter.

REFINING AND MARKETING OPERATIONS

Our refining and marketing operations, operating under the North Atlantic trade name, are comprised of a medium gravity sour crude hydrocracking refinery with a 115,000 bbl/d capacity and a marketing division with 64 gasoline outlets, a home heating business and a commercial and wholesale petroleum products business, all located in the province of Newfoundland and Labrador. The marketing division has an average daily sales volume of approximately 11,000 barrels representing approximately a 15% to 20% share of the Newfoundland and Labrador market.

The following summarizes the North Atlantic financial and operational information for the three and six month periods ended June 30, 2007 as well as the three months ended March 31, 2007 and the period from October 19, 2006 to December 31, 2006:

(in $000’s except where noted below)				October 19,
	Three Months	Three Months	Six Months	2006 to
	Ended June 30,	Ended March 31,	Ended June 30,	December 31,
	2007	2007	2007	2006

Revenues	900,387	784,045	1,684,432	460,359

Purchased products for resale and processing	708,642	632,296	1,340,938	386,014

Gross Margin⁽¹⁾	191,745	151,749	343,494	74,345

Costs and expenses
Operating expense	26,584	25,361	51,945	18,378
Purchased energy expense	18,337	24,000	42,337	15,685
Marketing expense	9,059	7,343	16,402	5,060
General and Administrative	402	300	702	-
Unrealized loss on risk management contracts	3,164	-	3,164	-
Depreciation and amortization expense	18,185	19,389	37,574	15,482

Earnings from operations⁽¹⁾	116,014	75,356	191,370	19,740

Cash capital expenditures	9,871	4,883	14,754	21,411

Feedstock volume (bbl/day)	115,570	113,711	114,646	86,890

Yield (000’s barrels)
Gasoline and related products	3,379	3,310	6,689	1,875
Ultra low sulphur diesel	4,020	4,213	8,233	2,624
Heavy fuel oil	2,950	2,745	5,695	1,752
Total	10,349	10,268	20,617	6,251

Average Refining Margin (US$bbl)	$15.64	$11.85	$13.69	$9.32

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

Overview of Refining and Marketing Operations

Since completion of an extended refinery turnaround in November 2006, North Atlantic’s earnings from operations have reflected near capacity operating performance with minimal disruptions while the First Quarter and Second Quarter of 2007 have also benefited from a very strong market for refined products. North Atlantic’s daily throughput has averaged approximately 114,646 barrels during the six month period ended June 30, 2007 comprised of 104,530 barrels of crude oil and 10,116 barrels of vacuum gas oil as compared to the three months ended June 30, 2007 with daily throughput averages of 115,570 barrels, 104,659 barrels and 10,911 barrels, respectively. North Atlantic’s refining margins reflect the improved crack spread for gasoline and heating oil which have been impacted by both an unusual number of disruptions at North American refineries as well as the expected seasonal increase in gasoline demand for the summer driving season offset by a narrowing of the differential between its medium gravity sour crude oil feedstock price and the North American benchmark for light sweet crude oil, West Texas Intermediate prices.

Refining Benchmark Prices

The refining industry has a few benchmark prices against which to compare refinery performance. Typically, these benchmarks include prices for refined products such as Reformulated Blendstock for Oxygenate Blending gasoline ("RBOB gasoline") and heating oil. The New York Mercantile Exchange ("NYMEX") "2-1-1 Crack Spread" is a refining benchmark calculated assuming that the processing of two barrels of light sweet crude oil (defined as a WTI quality) produces one barrel of RBOB gasoline and one barrel of heating oil delivered to the New York market where product prices are set in relation to the NYMEX gasoline and NYMEX heating oil prices. The following refining industry benchmark prices are provided as reference points with which to index the North Atlantic refinery’s performance:

	Three Months	Three Months	Six Months	October 19,
	Ended June 30,	Ended March 31,	Ended June 30,	2006 to
	2007	2007	2007	December 31,
				2006

West Texas Intermediate crude oil (US$ per barrel)	65.03	58.16	61.60	60.44
RBOB gasoline (US$ per barrel/US$ per gallon)	93.79/2.23	71.08/1.69	82.62/1.97	66.78/1.59
Heating Oil (US$ per barrel/US$ per gallon)	80.27/1.91	69.86/1.66	75.15/1.79	71.82/1.71
2-1-1 Crack Spread (US$ per barrel)	22.00	12.31	17.29	8.86

Canadian / U.S. dollar exchange rate	0.911	0.854	0.881	0.883

Although the "2-1-1 Crack Spread" is a common industry benchmark, the North Atlantic refinery’s production differs in that it also produces approximately 25% to 30% heavy fuel oil not represented in the "2-1-1 Crack Spread" benchmark and also processes primarily a medium gravity sour crude oil rather than a WTI quality of light sweet crude oil. In addition, North Atlantic purchases approximately 8,000 to 10,000 bbl/d of additional vacuum gas oil to optimize the throughput of its hydrocracker unit which is a key unit in the production of gasoline and diesel fuel.

During the Second Quarter of 2007, the NYMEX price of RBOB gasoline and heating oil appreciated US$22.71/bbl and US$10.41/bbl, an increase of 32% and 15% over the prior quarter, respectively, while the WTI benchmark price increased by US$6.79/bll, a 12% increase over the prior quarter. This represents a crack spread increase during the quarter of US$15.92/bbl for RBOB gasoline and US$3.63/bbl for heating oil while the benchmark "2-1-1 Crack Spread" increased by US$9.69/bbl to US$22.00/bbl, a 79% increase over the prior quarter.

Refinery Feedstock

The cost and volume of North Atlantic’s crude oil feedstocks for the three months ended June 30, 2007 and March 31, 2007 were as follows:

	Three Months Ended June 30, 2007			Three Months Ended March 31, 2007
	Cost of	Volume	Cost per	Cost of	Volume	Cost per
	Feedstock		Barrel⁽¹⁾	Feedstock		Barrel⁽¹⁾
	(000’s of Cdn $)	(000s of bbls)	(US$/bbl)	(000’s of Cdn $)	(000s of bbls)	(US$/bbl)

Basrah	436,452	6,793	58.53	422,856	7,002	51.55
Hamaca	75,524	1,215	56.63	96,977	1,664	49.75
Urals	109,631	1,516	65.88	42,376	730	49.55
Crude Oil Feedstock	621,607	9,524	59.46	562,209	9,396	51.07
Vacuum Gas Oil	76,351	993	70.04	57,996	838	59.06
	697,958	10,517	60.46	620,205	10,234	51.73
Other costs	542			(819)
	698,500			619,386

(1) Cost of feedstock includes all costs of transporting the crude oil to North Atlantic’s refinery.

During the Second Quarter of 2007, the Refinery feedstock was comprised of 104,659 bbl/d of medium sour crude oil (approximately 71% Basrah Light from Iraq, 13% Hamaca from Venezula and 16% Urals from Russia) as compared to 104,400 bbl/d of medium sour crude oil (approximately 74% Basrah Light from Iraq, 18% Hamaca from Venezula and 8% Urals from Russia) in the prior quarter. During the Second Quarter, a heat exchange and fouling issue in the Refinery’s crude unit vacuum tower resulted in a lower yield of vacuum gas oil and a higher consumption of purchased vacuum gas oil with 10,911 bbl/s purchased in the current quarter as compared to 9,311 bbl/d in the prior quarter. The 1,600 bbl/d increase in purchased vacuum gas oil represents an incremental feedstock cost to replace material consumed by the Refinery and a significant contributing factor to the Second Quarter’s 98.40% yield as compared to the 100.33% yield of the prior quarter.

The price of North Atlantic’s crude oil feedstock averaged US$59.46 per barrel during the three months ended June 30, 2007 as compared to US$51.07 for the prior three month period, a 16% increase in feedstock costs as the global demand for crude oil strengthened with discounts against the benchmark prices narrowing. Relative to the 12% increase in the WTI benchmark, North Atlantic’s cost increase is driven primarily by a change in its feedstock blend to increase its consumption of Urals to 16% as compared to 8% in the prior quarter. Urals are expected to provide slightly better gasoline and distillate yields however our heat exchange and fouling issue during the Second Quarter distorted the expected benefit. During the Second Quarter, the feedstock cost for Basrah and Hamaca increased by approximately 14% over the prior quarter mirroring the 12% increase in the WTI benchmark and reflecting a stable differential between North Atlantic’s cost of medium gravity sour crude oil feedstock and the WTI benchmark price which had narrowed appreciably during the First Quarter of 2007 to approximately US$7.00 per barrel.

Refined Products

Product yields are impacted by the crude oil feedstock as well as refinery performance. During the Second Quarter of 2007, North Atlantic’s gasoline production was unchanged at 32% of feedstock consumed while the yield of ultra low sulphur diesel and jet fuel dropped to 39% from 41% in the prior quarter and the production heavy fuel oil increased to 29% from 27% primarily as a result of the heat exchange and fouling issue in the crude unit vacuum tower. A summary of North Atlantic’s product yield, pricing and revenue for the three month periods ended June 30, 2007 and March 31, 2007 are as follows:

	Three Months Ended June 30, 2007			Three Months Ended March 31, 2007
	Refinery	Volume	Product	Refinery	Volume	Product
	Revenues		Price⁽¹⁾	Revenues		Price⁽¹⁾
	(000’s of Cdn $)	(000s of bbls)	($ per bbl/	(000’s of Cdn $)	(000s of bbls)	($ per bbl/
			$ per US gal)			$ per US gal)

Gasoline and related products	334,391	3,210	94.90/2.26	277,227	3,333	70.99/1.69
Low & ultra low	366,846	3,912	85.43/2.03	360,810	4,154	74.18/1.76
sulphur diesel & jet fuel
Heavy fuel oil	177,873	3,066	52.85/1.26	123,300	2,627	40.08/0.95
	879,110	10,188		761,337	10,114
Inventory adjustment		161			154
		10,349			10,268
Yield (as a % of Feedstock) ⁽²⁾		98.40%			100.33%

(1) Product prices are based on the sales at the North Atlantic refinery loading docks.

⁽²⁾After adjusting for changes in inventory held for resale

Relative to a benchmark NYMEX RBOB gasoline price, North Atlantic received a US$0.03 per bbl premium for its gasoline during the Second Quarter of 2007 as compared to no premium in the prior quarter. For its ultra low sulphur diesel and jet fuel products, North Atlantic received a US$0.12 per gallon premium for the three months ended June 30, 2007 as compared to a US$0.10 per gallon premium in the prior three month period relative to the NYMEX heating oil benchmark price. Generally, North Atlantic’s gasoline price will closely mirror the NYMEX reference price while its diesel fuel and jet fuel command a premium of approximately US$0.10 per gallon over the NYMEX heating oil price reflecting its higher product quality net of shipping costs to the New York harbour.

Relative to the average price paid for its crude oil feedstock, the selling price of North Atlantic’s heavy fuel oil resulted in a negative contribution of US$6.61 per barrel and aggregated to approximately $22.2 million for the three month period ended June 30, 2007 compared to a negative contribution of US$10.39 per barrel and $33.4 million in the First Quarter of 2007. The heavy fuel oil produced by North Atlantic presents an opportunity to re-configure the Refinery to produce more gasoline and/or diesel fuel which is the objective of the $22 million visbreaker enhancement approved in March 2007.

Gross Margin

North Atlantic’s gross margin is comprised of the crack spread from its refinery operations as well as the margin on its marketing and other related businesses. A summary of the gross margin contribution from the refinery and marketing operations for each three month period ended June 30, 2007 and March 31, 2007 are as follows:

	Three Months Ended June 30, 2007			Three Months Ended March 31, 2007
(000’s of Canadian dollars)	Refining	Marketing	Total	Refining	Marketing	Total

Sales revenue⁽¹⁾	879,110	115,404	900,387	761,337	91,290	784,045
Cost of products for processing and resale⁽¹⁾	698,500	104,269	708,642	619,386	81,492	632,296
Gross margin⁽²⁾	180,610	11,135	191,745	141,951	9,798	151,749
Average Refining	$15.64			$11.85
Margin (US$/bbl)

(1) The North Atlantic sales revenue and cost of products for processing and resale are net of inter-segment sales of $94,127,000 reflecting the refined products produced by the Refinery Operations and sold by the Marketing Operations for the three months ended June 30, 2007 ($68,582,000 for the three months ended March 31, 2007)

⁽²⁾ These are non-GAAP measures; please refer to "Non-GAAP Measures" in this MD&A.

During the three months ended June 30, 2007, North Atlantic’s crack spread of $180.6 million is comprised of $212.1 million of gross margin on the production of gasoline and ultra low sulphur diesel and jet fuel from its crude oil feedstock (including a heavy sour differential of approximately $39.0 million) and $27.3 million on the production of gasoline and ultra low sulphur diesel and jet fuel from purchased VGO offset by a $58.8 million negative contribution from the production of heavy fuel oil and other refined products. This compares to gross margin of $142.0 million comprised of $162.6 million (including $55.3 million of heavy sour differential), $15.8 million and $36.4 million, respectively, for the prior period.

As compared to the 79% appreciation in the "2-1-1 Crack Spread" benchmark during the Second Quarter of 2007 over the First Quarter, North Atlantic’s average refining margin increased to US$15.64, a 32% increase over the prior quarter. North Atlantic did not fully participate in this appreciation of the "2-1-1 Crack Spread" as its average cost of medium gravity sour crude oil increased by 17% as compared to a 12% increase in the WTI benchmark price and the "2-1-1 Crack Spread" benchmark assumes no production of heavy fuel oil, while North Atlantic produced 29% heavy fuel oil at a lower US$6.61 discount to the average cost of feedstock as compared to US$10.39 in the prior quarter.

The gross margin from North Atlantic’s marketing operations of $11.1 million (up $1.3 million from the prior period) is composed of the margin from both the retail and wholesale distribution of gasoline, home heating fuels and related appliances as well as the revenues from marine services including tugboat revenues.

Price Risk Management

Details of our price risk management contracts outstanding at June 30, 2007 are included in Note 16 of our interim consolidated financial statements for the three and six month periods ended June 30, 2007 filed on SEDAR at www.sedar.com. Subsequent to acquiring North Atlantic, Harvest’s participation in the crude oil value chain extended through to include the price of refined products produced by North Atlantic, principally gasoline, distillates (which encompasses low sulphur diesel fuel, jet fuel and heating oil) and heavy fuel oil. This results in our price protection of future cash flows including price protection on refined products. For purposes of this MD&A and the segmented reporting in Note 17 of our financial statements, our price risk management contracts are presented as either relating to our petroleum and natural gas operations or our refining and marketing operations according to the price exposure that is being managed.

During the Second Quarter of 2007, North Atlantic entered into the price risk management contracts with respect to an aggregate of 20,000 bbl/d comprised of the following contracts on 12,000 bbl/d of NYMEX heating oil and 8,000 bbls/d of Platts fuel oil for the period from January 2008 through December 2008:

Quantity	Contract Type	Contracted Price (in $U.S. per gallon unless specified otherwise)
2,000 bbls/d	Price Collar – Heating Oil	Price Floor – US$190.00 and Price Cap – US$217.50 (in cents per US gallon)
2,000 bbls/d	Price Collar – Fuel Oil	Price Floor – US$51.00 and Price Cap – US$58.68 (US$ per bbl)
		If NYMEX price is over US$222.17, price received is US$222.17
		If NYMEX price is between US$221.17 and US$193.00, price received is market price
10,000 bbls/d	3 Way Structure - Heating Oil	If NYMEX price is between US$193.00 and US$145.00, price received is US$193.00
		If NYMEX price is under US$145.00, price received is market price plus US$48.00
		If Platts price is over US$63.21, price received is US$63.21
		If Platts price is between US$63.21 and US$51.67, price received is market price
6,000 bbls/d	3 Way Structure - Fuel Oil	If Platts price is between US$51.67 and US$43.00, price received is US$51.67
		If Platts price is under US$43.00, price received is market price plus US$8.67

Concurrently with its entering into the above price risk management contracts for refined products, North Atlantic entered into the following inter-company contracts with Harvest’s petroleum and natural gas operations group to shift the WTI price protection to our petroleum and natural gas operations:

Quantity	Contract Type	Contracted Price
4,000 bbls/d	Price Collar	Price Floor – US$66.00 and Price Cap – US$75.79
16,000 bbls/d	3 Way Structure	If WTI price is over US$79.57, price paid is US$79.57
		If WTI price is between US$79.57 and $67.03, price paid is market price
		If WTI price is between US$67.03 and US$52.33, price paid is US$67.03
		If WTI price is under US$52.33, price paid is market price plus US$14.70

During the Second Quarter of 2007, the refined products contracts resulted in a net unrealized loss of $8.7 million of which $3.2 million is recognized in the North Atlantic operations as a net loss on a crack spread position and $5.5 million is recognized in the petroleum and natural gas operations as a loss on the WTI portion of the contract.

The table below provides a summary of net gains and losses on our price risk management contracts for the three month period ended June 30, 2007 and 2006:

	Three Months Ended June 30
	2007							2006
(000s)	Heating Oil		Fuel Oil		Total			Total

Unrealized loss on refined product price risk management contracts	$	(6,156)	$	(2,495)	$	(8,651)	$	-
Unrealized gain on inter-company WTI portion of refined product price risk management contracts		3,303		2,184		5,487		-
Net unrealized loss on price risk management contracts	$	(2,853)	$	(311)	$	(3,164)	$	-

Operating Expenses

A summary of North Atlantic’s operating costs for the refinery and marketing operations for the three month period ended June 30, 2007 and March 31, 2007 are as follows:

	Three Months Ended June 30, 2007			Three Months Ended March 31, 2007
(000’s of Canadian dollars)	Refining	Marketing	Total	Refining	Marketing	Total

Operating expense	22,122	4,462	26,584	21,031	4,330	25,361
Purchased energy	18,337	-	18,337	24,000	-	24,000
	40,459	4,462	44,921	45,031	4,330	49,361

The largest component of operating expense is wages and benefits which totaled $13.7 million during the Second Quarter of 2007 ($14.8 million for the three months ended March 31, 2007) while the other significant components were maintenance and repairs costs $3.0 million ($3.4 million for the three months ended March 31, 2007), insurance $1.7 million ($1.9 million for the three months ended March 31, 2007) and professional services $1.6 million ($1.1 million for the three months ended March 31, 2007), which were all in line with expectations. During the Second Quarter, refining operating expenses were $2.10 per barrel unchanged from $2.08 per barrel during the prior quarter. This is slightly lower than our expectations of approximately $2.20 to $2.40 per barrel due to the higher than anticipated throughput.

Purchased energy, consisting of low sulphur fuel oil and electric power, is required to provide heat and power to refinery operations, respectively. Our purchased energy costs dropped to $1.74 per barrel during the Second Quarter of 2007 as compared to $2.35 per barrel during the First Quarter as the refinery requires less heat during the warmer spring/summer season as well as an increase in internally produced fuel gas from the crude unit vacuum tower discussed earlier. Our expectation is that purchased energy should average approximately $2.20 for a calendar year.

Marketing Expense

During the Second Quarter of 2007, marketing expense is comprised of $1.0 million of marketing fees (based on US $0.08 per barrel of feedstock) to acquire feedstock (unchanged from the First Quarter) and $8.1 million of "Time Value of Money" charges both pursuant to the supply and offtake agreement. The "Time Value of Money" charges for the First Quarter totaled $6.3 million and reflect the lower cost of crude oil feedstock acquired in the First Quarter.

Capital Expenditures

Capital spending for the first six months of 2007 totals $14.8 million with the Second Quarter accounting for $9.9 million of the total in respect of tank recertification ($2.0 million), preliminary work on heat exchanger bundles for the hydrocracker unit that will be "cleaned out" during the planned maintenance shutdown in the Fourth Quarter ($1.0 million) along with numerous other sustaining and improvement projects.

Depreciation and Amortization Expense

North Atlantic’s depreciation and amortization expense for the refinery and marketing operations for the three month ended June 30, 2007 as well as March 31, 2007 is as follows:

	Three Months Ended June 30, 2007			Three Months Ended March 31, 2007
(000’s of Canadian dollars)	Refining	Marketing	Total	Refining	Marketing	Total

Tangible assets	16,111	470	16,581	17,183	495	17,678
Intangible assets	1,221	383	1,604	1,304	407	1,711
	17,332	853	18,185	18,487	902	19,389

The process units are amortized over an average useful life of 20-30 years. The intangible assets, consisting of engineering drawings, customer lists and fuel supply contracts, are amortized over a period of 20 years, 10 years and the term of the expected cash flows, respectively.

Goodwill

On October 19, 2006, we recorded $203.9 million of goodwill in connection with the acquisition of North Atlantic as the purchase price of the acquired business exceeded the fair value of the net identifiable assets and liabilities of that acquired business. As the refining assets are held in a self-sustaining subsidiary with a U.S. dollar functional currency, the value of the goodwill will be adjusted at each period end to reflect the changing U.S. dollar currency exchange rate. Goodwill will be 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. No charge for impairment of this goodwill has been made.

FINANCING AND OTHER

Interest Expense
		Three Months Ended June 30					Six Months Ended June 30

(000s)		2007		2006	Change		2007		2006	Change
Interest on short term debt
Bank loan	$	(71)	$	76	(193%)	$	1,099	$	226	386%
Convertible debentures		648		-	100%		1,294		-	100%
Amortization of deferred finance charges – short term debt		-		11	n/a		1,811		11	16,364%
		577		87	563%		4,204		237	1,674%

Interest on long-term debt
Bank loan		17,530		2,937	497%		36,706		4,240	766%
Convertible debentures		15,946		4,623	245%		30,394		7,919	284%
7^7/8% Senior Notes		5,659		5,573	2%		11,805		11,297	4%
Amortization of deferred finance charges – long term debt		668		761	(12%)		1,347		2,195	(39%)
		39,803		13,894	186%		80,252		25,651	213%
Total interest expense	$	40,380	$	13,981	189%	$	84,456	$	25,888	226%

Interest expense, which includes the amortization of related financing costs, was $26.4 million and $58.6 million higher respectively for the three and six month periods ended June 30, 2007 than in the same period in the prior year. Of this increase, the amount related to bank loan interest (both short term and long term) of $14.4 million and $33.3 million for the three month and six month periods, respectively, is the result of the significant increase in the drawn amounts on our credit facilities. A further $12.0 million and $23.8 million for the three and six month periods, respectively, is related to the increase in the principal amount of convertible debentures outstanding.

At the end of the Second Quarter of 2007, we had drawn approximately $1,048.0 million of bank borrowings as compared to $1,363.2 million at the end of the First Quarter of 2007 and $1,595.7 million at the end of December 31, 2006. During the First Quarter of 2007, our bank borrowings were reduced with the net proceeds of $357.4 million from our issuance of 6,146,750 trust units and $230 million principal amount of 7.25% Debentures due 2014. During the Second Quarter of 2007, our bank borrowings were reduced by a combination of net proceeds of $218.5 million from our issuance of 7,302,500 Trust Units and surplus cash after capital spending distribution requirements. The early repayment of our Senior Secured Bridge Facilities in the First Quarter of 2007 resulted in our accelerating the expensing of $1.8 million of unamortized commitment fees related to this facility. Currently, the interest on our Three Year Extendible Revolving Facility is at a floating rate based on 70 basis points over bankers’ acceptances for Canadian dollar borrowings and 70 basis points over the London Inter Bank Order Rate for US dollar borrowings. During the Second Quarter of 2007, our interest charges on bank loans aggregated to $17.5 million as compared to $20.3 million during the First Quarter of the year. Further details on our credit facilities and the bridge financing are included under "Liquidity and Capital Resources".

The interest on our convertible debentures totaled $31.7 million during the first six months of 2007 and is based on the effective yield of the debt component of the convertible debentures. Details on the convertible debentures outstanding are fully described in Note 11 to the interim consolidated financial statements for the three and six month periods ended June 30, 2007 filed on SEDAR at www.sedar.com. During the Second Quarter of 2007, there were $125.6 million of principal amount of convertible debentures converted to 4,613,915 Trust Units as compare to an aggregate of $333,000 principal amount of convertible debentures converted to 19,731 Trust Units in the First Quarter of the year.

Included in short and long term 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 amortization of commitment fees and legal costs incurred for our credit and bridge facilities, all totaling $3.2 million for the six months ended June 30, 2007.

Non-Controlling Interest

The non-controlling interest in the first quarter of 2006 represents the net income attributed to non-controlling interest holders for the period. The exchangeable shares that give rise to the non-controlling interest were issued by Harvest Operations as partial consideration for the purchase of a corporate entity in 2004. In 2006, 156,067 exchangeable shares were converted to trust units under the plan of arrangement with Viking and the remaining 26,902 exchangeable shares were purchased and cancelled for a total cash payment of $1.0 million.

Currency Exchange Gains and Losses

Currency 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 LIBOR bank loans, 7^7/8% Senior Notes as well as any other U.S. dollar cash balances. Since December 31, 2006, the Canadian dollar has strengthened significantly compared to the U.S dollar. As a result we incurred an unrealized gain on our 7^7/8% Senior Notes of $24.3 million and a further $55.2 million in respect of our U.S. dollar denominated LIBOR bank loans that are held in connection with the purchase of North Atlantic. The LIBOR loan balance at the beginning of the year was approximately US$650 million, but in early May we repaid approximately US$160 million of this balance and realized a $3.5 million currency exchange gain. In addition, we also incurred $0.5 million of unrealized foreign exchange losses on transactions incurred by North Atlantic and realized losses of $0.6 million.

North Atlantic is considered a self-sustaining operation with a U.S. dollar functional currency. The foreign exchange gains and losses incurred by North Atlantic relate to Canadian dollar transactions converted to U.S. dollars as their functional currency is U.S. dollars.

Future Income Tax

With the enactment of Bill C-52 in the Second Quarter of 2007, Harvest recorded a future income tax expense of $177.7 million to reflect the impact of the 31.5% tax to be applied to distributions from Canadian publicly traded income trusts commencing in January 2011. We recorded a $177.7 million future income tax expense and a corresponding future income tax liability related to the timing differences between the book value and the tax basis of assets held by our mutual fund trust. While net income in the Second Quarter of 2007 is reduced significantly by this future income tax adjustment, there is no impact on Funds From Operations.

Contractual Obligations and Commitments

We have contractual obligations and commitments in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, and land lease obligations. These obligations are of a recurring and consistent nature and impact cash flow in an ongoing manner. We also have contractual obligations and commitments that are of a less routine nature as disclosed in the following table:

	Maturity
Annual Contractual Obligations (000s)	Total	Less than 1 year	1-3 years	4-5 years	After 5 years
Long-term debt	1,314,315	-	65,000	1,249,315	-
Interest on long-term debt⁽⁴⁾	253,162	39,782	157,363	56,017	-
Interest on convertible debentures⁽³⁾	293,208	25,875	98,272	95,190	73,871
Operating and premise leases	17,613	3,447	11,331	2,577	258
Capital commitments⁽⁵⁾	16,533	13,653	2,880	-	-

Asset retirement obligations⁽⁶⁾	696,003	8,360	13,058	13,321	661,264
Transportation ⁽⁷⁾	4,441	1,064	2,646	542	189
Purchase commitments	7,275	7,275	-	-	-
Pension contributions	27,687	390	3,345	4,805	19,147
Feedstock commitments	671,642	665,915	5,727	-	-
Total	3,301,879	765,761	359,622	1,421,767	754,729

(1) As at June 30, 2007, we had entered into physical and financial contracts for production with average deliveries of approximately 25,000 barrels of oil equivalent per day for the remainder of 2007, and 10,000 barrels of oil equivalent per day in 2008. We have also entered into financial contracts to minimize our exposure to fluctuating electricity prices. Please see Note 16 to the interim consolidated financial statements for further details.

(2) Assumes that the outstanding convertible debentures either convert at the holders’ option or are redeemed for Units at our option.

(3) Assumes no conversions and redemption by Harvest for trust units at the end of the second redemption period. Only cash commitments are presented.

(4) Assumes constant foreign exchange rate.

(5) Relates to drilling commitments.

(6) Represents the undiscounted obligation by period

(7) Relates to firm transportation commitment on the Nova pipeline.

Off Balance Sheet Arrangements

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.

Related Party Transactions

During the Second Quarter of 2007, Vitol Refining S.A. purchased $131.2 million of Iraqi crude oil pursuant to the terms and conditions of the Supply and Offtake Agreement from a company in which a director of Harvest holds a minority equity interest. Management of Harvest pursues the best available terms for its crude oil supply from all available sources. As at June 30, 2007, no amounts related to these purchases are included in Harvest’s accounts payable and accrued liabilities, however, there is $136.4 million included in the total feedstock commitments disclosed at the end of June 2007 and a further U.S. $65.5 million of commitments incurred after June 30, 2007 related to crude oil purchases by Vitol Refining S.A from this private company related to a Harvest director.

CHANGE IN ACCOUNTING POLICIES

Effective January 1, 2007, we have retrospectively without restatement adopted the new accounting standards of the Canadian Institute of Chartered Accountants respecting, "Financial Instruments – Recognition and Measurement"; "Comprehensive Income"; and "Financial Instruments – Disclosure and Presentation". The impact of adopting these new standards is reflected in our financial results for the six month period ended June 30, 2007 while the prior year comparative financial statements have not been restated. While the new standards change how we account for financial instruments, there were no material impacts on our results for the three and six month periods ended June 30, 2007 with the most significant difference being that the deferred charges previously presented as an asset are now netted against the respective debt and amortized to income using an effective interest rate. For a description of the new accounting standards and the impact on our financial statements of adopting such standards see Note 2 to the interim consolidated financial statements for the three and six month periods ended June 30, 2007.

LIQUIDITY AND CAPITAL RESOURCES

At the end of June 30, 2007, we had total debt and equity of $5,651.5 million, an increase of $95.3 million compared to $5,556.2 million at the end of December 2006. During the first six months of 2007, the significant changes to our capital structure were:

The issuance of $230 million principal amount of Convertible Unsecured Subordinated Debentures and 6,146,750 Trust Units with net proceeds of $357.4 million in the First Quarter that were applied to fully repay the Senior Secured Bridge Facility with the remaining $67.7 million applied to reduce the drawn amount of our Three Year Extendible Revolving Credit Facility,

The issuance of 7,302,500 Trust Units with net proceeds of $218.5 million in the Second Quarter that were applied to reduce the drawn amount of our Three Year Extendible Revolving Credit Facility, and

The issuance of 3,316,725 Trust Units pursuant to our Premium Distribution^TM, Distribution Reinvestment and Optional trust unit Purchase Plan (the "DRIP Plans") raising $87.7 million.


(in millions)	June 30, 2007	December 31, 2006
DEBT
Credit Facilities
- Three Year Extendible Revolving Credit Facility	$1,048.0	$1,306.0
- Senior Secured Bridge Facility	-	289.7
Total Bank Debt	1,048.0	1,595.7

7^7/8 % Senior Notes Due 2011 (US$250 million) ⁽¹⁾	266.4	291.4

Convertible Debentures, at principal amount
10.5% Debentures Due 2008	25.5	26.6
9% Debentures Due 2009	1.1	1.2
8% Debentures Due 2009	1.8	2.2
6.5% Debentures Due 2010	37.9	37.9
6.4% Debentures Due 2012	174.6	174.8
7.25% Debentures Due 2013	379.4	379.5
7.25% Debentures Due 2014	106.0	-
Total Convertible Debentures	726.3	622.2

Total Debt	2,040.7	2,509.3

TRUST UNITS
143,505,858 issued at June 30, 2007	3,610.8
122,096,172 issued at December 31, 2006		3,046.9

TOTAL DEBT AND TRUST UNITS	$5,651.5	$5,556.2

TOTAL DEBT TO TOTAL CAPITALIZATION	36%	45%
⁽¹⁾Face value converted at the period end exchange rate.

During the six months ended June 30, 2007, our Funds From Operations totaled $458.4 million and we declared distributions to our Unitholders aggregating to $299.3 million. During this period, $203.4 million cash distributions were paid (net of $87.7 million which was reinvested through our distribution reinvestment plans) and $255.0 million of Funds From Operations was retained for our capital programs and our working capital repayment. In the six months ended June 30, 2007, our capital spending aggregated to $211.5 million while the net cash required for our acquisition/divestiture program aggregated to $9.2 million with the $26.1 million of residual Funds From Operations directed towards our increasing working capital requirements. This compares with Funds From Operations of $248.0 million ($242.3 million after including $5.7 million of one time cash transaction costs relating to the acquisition of Viking) and distributions declared of $210.7 million net of $79.3 million reinvested through our distribution reinvestment plans in the prior year with aggregate capital spending of $157.5 million.

Management, together with the Board of Directors of Harvest, continually assess distributions relative to projections of Funds From Operations, debt leverage and capital spending plans. On July 8, 2007 we announced the declaration of a $0.38 per trust unit distribution for each of July, August and September 2007 based on forecasted commodity prices and expected operating performance that are consistent with the current environment. Of the distributions declared for the first six months of 2007 totaling $299.3 million and representing 65% of Funds From Operations, $89.2 million have been settled with trust units as a result of Unitholders choosing to participate in our distribution reinvestment plans, representing a participation rate of approximately 30%.

In February 2007, we issued 6,146,750 trust units and $230 million principal amount of 7.25% Debentures due 2014 for net proceeds of $357.4 million and applied these proceeds to fully repay the remaining balance outstanding on the Senior Unsecured Bridge Facility. The residual $67.7 million of proceeds was applied to the then $1.4 billion Three Year Extendible Revolving Credit Facility thereby increasing our undrawn credit capacity. In June 2007, we issued 7,302,500 trust units for net proceeds of $218.5 million and also applied the proceeds to reduce the drawn amount of our $1.6 billion Three Year Extendible Revolving Credit Facility.

During the Second Quarter of 2007, the trading value of our trust units appreciated from an opening price of $28.57 at the beginning of the quarter to $32.95 at the end of the quarter and traded as high as $34.48 in mid June. This appreciation in the value of our Trust Units supported the conversion of $125.6 million of principle amount of 7.25% Debentures due 2014, primarily in late June. Continued strength in the trading value of our trust units in the Third Quarter is expected to encourage the conversion of more convertible debentures as all but one series of debentures have exercise prices of $32.20 per trust unit or less. While these conversions do not bring additional cash into Harvest, they do contribute to improving our credit metrics as these debt instruments transition to equity.

In the First Quarter of 2007, we requested that our lenders extend the maturity date of our Three Year Extendible Revolving Credit Facility to April 2010 from March 2009 and approve the expansion of the facility from $1.4 billion to $1.6 billion. All lenders approved the expansion of the facility to $1.6 billion and we have received consents to extend the maturity date to April 2010 from lenders representing $1,535 million of commitments, with one lender representing a $65 million commitment not consenting to an extension of the maturity date. Subsequent to the end of the Second Quarter, we received commitments from one existing lender to replace $35 million of commitments maturing March 2009, resulting in only $30 million of our $1.6 billion Three Year Extendible Revolving Credit Facility maturing March 2009. For a complete description of this covenant-based credit agreement, see Note 10 to our audited consolidated financial statements for the year ended December 31, 2006 filed on SEDAR at www.sedar.com. This credit facility contains floating interest rates that are expected to range between 65 and 115 basis points over bankers’ acceptance rates depending on our secured senior debt (excluding 7^7/8% Senior Notes and convertible debentures) to earnings before interest, taxes, depletion, amortization and other non-cash amounts ("EBITDA") with availability under this facility subject to:

Secured senior debt to EBITDA	3.0 to 1.0 or less
Total debt to EBITDA	3.5 to 1.0 or less
Secured senior debt to capitalization	50% or less
Total debt to capitalization	55% or less

At the end of June 30, 2007, our Bank Debt to annualized EBITDA based on the first six months of 2007 was 1.14 to 1.0, Total Debt (excluding convertible debentures) to annualized EBITDA was 1.43 to 1.0 while the Bank Debt to Total Capitalization was 19% and Total Debt to Total Capitalization was 36%.

Concurrent with the closing of the North Atlantic acquisition, North Atlantic entered into a Supply and Offtake Agreement with Vitol Refining S.A. ("Vitol"), a third party related to the vendor of North Atlantic. The agreement provides for the ownership of substantially all of the crude oil feedstock and refined product inventory at the Refinery be retained by Vitol and that Vitol will be granted the right and obligation to provide crude oil feedstock with delivery to the Refinery as well as the right and obligation to purchase all refined products produced by the Refinery. In addition to assisting North Atlantic by procuring the crude oil feedstock and marketing the refined products, this agreement also significantly reduces North Atlantic’s working capital commitments by eliminating the requirement for North Atlantic:

to post letters of credit for crude oil feedstock purchase commitments,
to arrange for the shipping of crude oil feedstock to the Refinery,
to pay for crude oil feedstock purchases while in-transit to and in tankage at the Refinery,

to finance the receivables from the sale of refined products, and
to arrange for the shipping of refined products to customers.

In respect of this working capital requirement assumed by Vitol, the Supply and Offtake Agreement provides that North Atlantic will pay a "Time Value of Money" charge reflecting an effective interest rate of 350 basis points over the London Inter Bank Offer Rate. The Supply and Offtake Agreement may be terminated by either party at the end of the initial two year term (October 2009), and at any time thereafter by providing notice of termination no later than six months prior to the desired termination date. The potential for termination of the Supply and Offtake Agreement requires that we maintain the financial flexibility to provide the working capital capacity currently provided by Vitol as well as either develop the internal capability to perform these supply services or identify and negotiate a similar contract with another provider of such services. At the end of June 30, 2007, we estimate that the outstanding commitments under the Supply and Offtake Agreement aggregated to approximately $671.6 million.

Following the October 31, 2006 announcement by the Government of Canada which proposed to apply a 31.5% tax on the distributions from certain publicly traded mutual funds including Harvest Energy Trust, the trading value of our trust units (which closed on October 31, 2006 at $32.95) has been as follows:

	Trading Price
Month	High		Low		Volume
TSX Trading
November 2006	$	28.60	$	24.76	2,903,180
December 2006	$	26.88	$	25.70	8,828,206
January 2007	$	26.22	$	23.20	12,822,502
February 2007	$	27.49	$	24.81	10,036,635
March 2007	$	29.22	$	25.90	11,430,584
April 2007	$	29.72	$	29.24	10,244,956
May 2007	$	31.94	$	31.39	13,984,905
June 2007	$	33.27	$	32.65	19,605,824

NYSE Trading (in US$)
November 2006	$	25.29	$	22.05	34,223,300
December 2006	$	23.43	$	22.27	16,264,800
January 2007	$	22.20	$	19.70	16,693,600
February 2007	$	23.55	$	21.18	10,059,454
March 2007	$	25.22	$	21.97	12,316,050
April 2007	$	26.21	$	25.80	10,038,123
May 2007	$	29.25	$	28.68	14,253,739
June 2007	$	31.24	$	30.66	13,474,838

Following the October 31, 2006 announcement, the trading value of our trust units sustained a significant drop in trading range and in June 2007 has surpassed the pre-announcement levels on the strength of rising commodity prices, narrowing oil quality differentials and robust refining margins. Maintaining the strength in the trading value of our trust units is critical as our trust units are the currency that enables us to optimize the accretive value of transactions, including our anticipated participation in the expected consolidation of the Canadian energy royalty trust sector, as well as minimizing the dilutive impact of issuing trust units to repay our debt.

We are authorized to issue an unlimited number of trust units. As at August 10, 2007, we had 145,299,537 trust units outstanding, 3,935,158 of Unit Appreciation Rights outstanding (of which 582,475 are exercisable) and 329,993 awards issued under the Unit Awards Incentive Plan (of which 86,497 were exercisable). In addition, we had seven series of convertible debentures outstanding that are convertible into 20,478,396 trust units.

Distributions to Unitholders and Taxability

In the Second Quarter of 2007, we declared monthly distributions of $0.38 per trust unit ($154.1 million) to Unitholders, 63% of our Funds From Operations, and have declared a monthly distribution of $0.38 per trust unit for the third quarter of 2007 as well. The $38.2 million increase in distributions declared during the Second Quarter of 2007 as compared to $115.9 million in the prior year is primarily due to an increase of approximately 41.3 million trust units outstanding following the acquisitions of Birchill and North Atlantic in 2006 along with issuance under our distribution re-investment plans.


		Three Months Ended June 30					Six Months Ended June 30
(000s except per trust unit amounts)		2007		2006	Change		2007		2006	Change
Distributions declared	$	154,057	$	115,889	33%	$	299,327	$	210,701	42%
Per trust unit	$	1.14	$	1.14	-	$	2.28	$	2.25	1%
Taxability of distributions		100%		100%	-		100%		100%	-
Payout ratio⁽¹⁾		63%		79%	(16%)		65%		85%	(20%)

(1) Funds From Operations used to calculate payout ratio excludes working capital changes, settlements of asset retirement obligations and in 2006, one time transaction costs associated with the Viking acquisition - see "Non-GAAP Measures".

Prior to January 1, 2011, 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 and that the Trust will have no taxable income.

OUTLOOK

During the first six months of 2007, we have benefited from stable refinery operations as well as robust refining margins and continued strength in crude oil prices while maintaining a stable monthly distribution of $0.38 per Trust Unit. As the third quarter unfolds, our focus on refining margins will shift from gasoline supplies for the summer driving season to a more balanced demand for heating oil and gasoline for the coming winter months. In our petroleum and natural gas operations, we do not attempt to forecast commodity prices although we note that natural gas prices have softened and the Canadian dollar has strengthened relative to the U.S. dollar and the crack spread on refined products has narrowed early in the Third Quarter.

For the balance of 2007, we have revised our daily production forecast to average 61,000 boe/d, including our acquisition of Grand effective in August 2007, and are adjusting our operating cost expectations to a range between $12.00 and $13.00 per boe for our petroleum and natural gas operations with our capital expenditures over the next six months to aggregate to $100 million. These production and operating cost expectations include the impact of the acquisition of Grand and anticipate that $10 million of capital spending on the Grand assets will be completed before year end. We will continue to evaluate acquisition opportunities as well as offer selected properties for divestment while striving to maintain or enhance our productive capability and improve our unit operating costs.

For our refining and marketing business, we are forecasting throughput for the Third Quarter in line with current operating performance at approximately 115,000 bbls/d of feedstock (excluding purchased fuel oil consumed by the plant). For the Fourth Quarter, we are anticipating throughput of approximately 102,000 bbls/d impacted by a planned maintenance shutdown of the Isomax unit for much of October to replace a catalyst bed and change-out its heat exchangers and this will lower the amount of gasoline and distillates produced during the Quarter. This modest turnaround may be extended to include minor modifications to the vacuum tower but this will not extend the length of the partial shutdown with current expectations being that the associated increased costs will be offset by improved distillate yields resulting in a neutral cash impact. We continue to expect our unit operating costs to be at the higher end of our $4.40 to $4.60 range with capital spending unchanged at $60 million and the cost of the turnaround estimated at $1.9 million. Should the shutdown include modifications to the vacuum tower, capital costs would be increased by $0.8 million.

Assuming a monthly distribution of $0.38 per trust unit is maintained, we continue to expect that our 2007 payout ratio will trend lower as compared to 2006 with our Funds From Operations benefiting from our acquisition of North Atlantic and a US$13.56 higher floor price in our 2007 oil price risk management contracts than in 2006.

Currently, we have entered into price risk management contracts to provide a floor price of US$55.67 (relative to the West Texas Intermediate benchmark price) with upside participation if prices rise above US$55.67 on 25,000 bbls/d for the balance of 2007. After considering our 19% average royalty rate, these risk management contracts reduce our WTI price risk exposure at prices under US$55.67 to 27% of our crude oil production, which significantly reduces the volatility of our Funds From Operations if WTI prices trend below the US$55.67 level. To complement these price risk management contracts, we have forward sold US$8,750,000 per month at an average Canadian to US dollar exchange rate of approximately US$0.89 per Canadian dollar through December 2007 and a further US$8,333,000 per month at US$0.90 per Canadian dollar for the first half of 2008, which represents approximately 20% of the US dollar value of the crude oil price risk management contracts. For the first half 2008, we have entered into price risk management contracts to provide a WTI floor price of US$55.00 with an 80% upside participation if prices rise above US$55.00 on 10,000 bbls/d, plus we have added contracts with respect to 20,000 bbls/d of refined products as more fully described in the Price Risk Management Contracts sections of this MD&A.

For 2008, we have entered into price collars on 4,000 bbl/d of refined products as well as 3-way structured contracts on a further 16,000 bbl/d of refined products as more fully described in the Price Risk management section of this MD&A’s discussion of Refining and Marketing Operations.

After crystallizing a $5.5 million gain on our natural gas price contracts early in the Third Quarter of 2007, we have exposure to future changes in natural gas prices. However, our financial results will include gains of $2.5 million, $2.1 million and $900,000 in each of the next three quarters, respectively. We have also entered into contracts to fix the price of 35 megawatt hours (or approximately 50% of the anticipated electrical consumption of our petroleum and natural gas operations in Alberta) through to the end of December 2008 at a price of $56.69. Our objective with the electricity fixed price contracts is to substantially reduce the volatility of our operating costs to fluctuations in the cost of electricity which represent approximately 25% of the operating costs in our petroleum and natural gas operations.

To enhance the stability to our future cash flows, we will continue to enter into contracts to protect the future price of refined products as well as AECO natural gas prices and the currency exchange rate for US dollars to Canadian dollars along with a measured approach to negotiating fixed prices for electricity. Our objective of stabilizing our future cash flows is to fund long term sustainable cash distributions in a wide variety of pricing environments.

In addition to our petroleum and natural gas growth strategies in western Canada of focusing on properties adjacent to our existing operations, we intend to be an active participant in the consolidation of Canadian energy royalty trusts, which is dependent on the current value of our trust units as trust-on-trust mergers are expected to be negotiated based on market valuations.

In June 2007, the Federal Government of Canada substantively enacted the changes to The Income Tax Act (Canada) to apply a 31.5% tax at the mutual fund trust level on distributions of certain income from publicly traded mutual fund trusts, including Harvest Energy Trust, with an effective date of January 1, 2011, as previously announced. As of June 30, 2007, we estimate that 58% of our Unitholders are non-Canadian residents, essentially unchanged since March 31, 2007 and a significant increase since February 2006 when non-Canadian residents owned 33%. As the taxation of publicly traded mutual fund trusts unfolds, we continue to search and validate various capital structures balancing the benefits of the tax efficient distributions prior to 2011 against the longer term benefits of continuing with a growth strategy beyond the announced "normal growth" limitations.

The following table reflects the sensitivity of our last six months of operations in 2007 to changes in the following key factors to our business:

		Assumption		Change	Impact on Cash Flow
WTI oil price (US$/bbl)	$	69.00	$	5.00	$	0.16 / Unit
Canadian/U.S. dollar exchange rate	$	0.93	$	0.02	$	0.14 / Unit
AECO daily natural gas price ($/mcf)	$	7.00	$	1.00	$	0.12 / Unit
Refinery crack spread (US$/bbl)	$	10.00	$	1.00	$	0.14 / Unit
Petroleum and natural gas operating expenses (per boe)	$	12.50	$	1.00	$	0.08 / Unit

SUMMARY OF QUARTERLY RESULTS

The table and discussion below highlight our second quarter 2007 performance over the preceding seven quarters on select measures:

		2007				2006								2005
(000s except where noted)		Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3
Revenue, net of royalties	$	1,133,450	$	1,025,512	$	682,744	$	259,818	$	257,103	$	181,160	$	154,646	$	169,654

Net income (loss)	$	6,248	$	69,850	$	1,533	$	107,768	$	60,682	$	(33,937)	$	75,638	$	52,862
Per trust unit, basic²	$	0.05	$	0.55	$	0.01	$	1.01	$	0.60	$	(0.41)	$	1.45	$	1.09
Per trust unit, diluted²	$	0.05	$	0.55	$	0.01	$	0.99	$	0.60	$	(0.41)	$	1.42	$	1.08

Funds From Operations¹	$	244,461	$	213,941	$	156,270	$	147,471	$	147,010	$	100,971	$	96,431	$	103,508
Per trust unit, basic¹	$	1.83	$	1.68	$	1.35	$	1.39	$	1.45	$	1.23	$	1.84	$	2.14
Per trust unit, diluted¹	$	1.62	$	1.52	$	1.29	$	1.34	$	1.43	$	1.22	$	1.81	$	2.09

Distributions per Unit, declared	$	1.14	$	1.14	$	1.14	$	1.14	$	1.14	$	1.11	$	1.05	$	0.95

Total long term financial liabilities	$	1,961,748	$	2,409,241	$	2,488,524	$	1,105,728	$	746,840	$	735,896	$	349,074	$	386,124
Total assets	$	5,613,333	$	5,800,346	$	5,745,558	$	4,076,771	$	3,455,918	$	3,470,653	$	1,308,481	$	1,327,272

(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.

Net revenues have generally increased steadily over the eight quarters with significantly higher revenue in the Second and Third Quarters of 2006 over the preceding quarters due to the incremental revenue from the Viking acquisition in February 2006 along with stronger commodity prices including narrowing crude oil differentials. In the Fourth Quarter of 2006, the significant increase in revenue over the prior quarter is attributed to the North Atlantic acquisition which is a margin business with significant revenues coupled with significant costs for crude oil feedstock. The growth in Funds From Operations is closely aligned with the growth in net revenues and is attributed to the same factors as the growth in net revenues.

Net income reflects both cash and non-cash items. Changes in non-cash items, including future income tax, DDA&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 cause net income to vary significantly from period to period. In the Second Quarter of 2007 Bill C-52 was substantively enacted, which imposed a new tax on distributions from publicly traded income trusts resulting in a large future income tax expense in the quarter. 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 and this is the primary reason why our net income (loss) does not reflect the same trends as net revenues or Funds From Operations.

Growth in total assets over the last eight quarters is directly attributed to our acquisition of Viking in the first quarter of 2006, Birchill in the Third Quarter of 2006 and North Atlantic in the Fourth Quarter of 2006. The changes in our total long term financial liabilities is primarily due to the impact of our acquisitions offset by our issuance of trust units and the net cash surplus of Funds From Operations over our distributions to Unitholders.

CRITICAL ACCOUNTING ESTIMATES

There are a number of critical estimates underlying the accounting policies applied when preparing the consolidated financial statements due to timing differences between when certain activities take place and when these activities are reported. Changes in these estimates could have a material impact on our reported results.

Reserves

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. In the process of estimating the economically recoverable oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions, such as:

Expected reservoir characteristics based on geological, geophysical and engineering assessments;
Future production rates based on historical performance and expected future operating and investment activities;

Future oil and gas prices and quality differentials; and
Future development costs.

We follow the full cost method of accounting for our oil and natural gas activities. 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 centre. Maintenance and repairs are charged against income, and renewals and enhancements that extend the economic life of the capital assets are capitalized. The provision for depletion and depreciation of petroleum and natural gas assets is calculated on the unit-of-production method, based on proved reserves as estimated by independent petroleum engineers.

Reserve estimates impact net income through depletion, the determination of asset retirement obligations and the application of an impairment test. Revisions or changes in the reserve estimates can have either a positive or a negative impact on net income, capital assets and asset retirement obligations.

The estimates in reserves impact many of our accounting estimates including our depletion calculation. A decrease of reserves by 10% would result in an increase of approximately $70 million in our depletion expense.

Asset Retirement Obligations

In the determination of our asset retirement obligations, management is required to make a significant number of estimates with respect to activities that will occur in many years to come. In arriving at the recorded amount of the asset retirement obligation numerous assumptions are made with respect to ultimate settlement amounts, inflation factors, credit adjusted risk free discount rates, timing of settlement and expected changes in legal, regulatory, environmental and political environments. The asset retirement obligation also results in an increase to the carrying cost of capital assets. The obligation accretes to a higher amount with the passage of time as it is determined using discounted present values. A change in any one of the assumptions could impact the estimated future obligation and in return, net income. It is difficult to determine the impact of a change in any one of our assumptions. As a result, a reasonable sensitivity analysis cannot be performed.

Impairment of Capital Assets

In determining if the capital assets are impaired there are numerous estimates and judgments involved with respect to our estimates. The two most significant assumptions in determining cash flows are future prices and reserves.

The estimates of future prices require significant judgments about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The prices used in carrying out our impairment test are based on prices derived from a consensus of future price forecasts among industry analysts. Given the significant assumptions required and the possibility that actual conditions will differ, we consider the assessment of impairment to be a critical accounting estimate.

If forecast WTI crude oil prices were to fall by 18% to 20%, the initial assessment of impairment indicators would not change; however, below that level, we would likely experience an impairment. Although oil and natural gas prices fluctuate a great deal in the short-term, they are typically stable over a longer time horizon. This mitigates potential for impairment.

Reductions in estimated future prices may also have an impact on estimates of economically recoverable proved reserves.

Any impairment charges would reduce our net income.

It is difficult to determine and assess the impact of a decrease in our proved reserves on our impairment tests. The relationship between the reserve estimate and the estimated undiscounted cash flows is complex. As a result, we are unable to provide a reasonable sensitivity analysis of the impact that a reserve estimate decrease would have on our assessment of impairment.

Employee Future Benefits

We maintain a defined benefit pension plan for the employees of North Atlantic. Obligations under employee future benefit plans are recorded net of plan assets where applicable. An independent actuary determines the costs of our employee future benefit programs using the projected benefit method. The determination of these costs requires management to estimate or make assumptions regarding the expected plan investment performance, salary escalation, retirement ages of employees, expected health care costs, employee turnover, discount rates and return on plan assets. The obligation and expense recorded related to our employee future benefit plans could increase or decrease if there were to be a change in these estimates. Pension expense represented less than 0.5% of our total expenses for 2006.

Purchase Price Allocations

Business acquisitions are accounted for by the purchase method of accounting. Under this method, the purchase price is allocated to the assets acquired and the liabilities assumed based on the fair values at the time of the acquisitions. The excess of the purchase price over the assigned fair values of the identifiable assets and liabilities is allocated to goodwill. In determining the fair value of the assets and liabilities we are often required to make assumptions and estimates about future events, such as future oil and gas prices, crack spreads and discount rates. Changes in any of these assumptions would impact amounts assigned to assets and liabilities and goodwill in the purchase price allocation and as a result, future net earnings.

RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

Convergence of Canadian GAAP with International Financial Reporting Standards

In 2006, Canada’s Accounting Standards Board ("AcSB") ratified a strategic plan that will result in Canadian GAAP, as used by public companies, being converged with International Financial Reporting Standards ("IFRS") over a transitional period. In early 2007, the AcSB issued a decision summary with respect to its progress on the implementation strategy of IFRS for publicly accountable enterprises and will confirm a changeover date from Canadian GAAP to IFRS in March of 2008. Currently, it is expected that the transition date will be January 1, 2011. This convergence initiative is in its early stages as of the date of these financial statements and we have the option to adopt U.S. GAAP at any time prior to the expected conversion date. Accordingly, it would be premature to assess the impact of the initiative, if any, on our financial statements at this time.

Financial Instruments – Disclosures and Presentation

On December 1, 2006, Canada’s Accounting Standards Board issued the following two new standards regarding the disclosure and presentation of financial instruments with an implementation date for annual and interim financial statements beginning on or after October 1, 2007.

Section 3862 – Financial Instruments – Disclosures

This standard requires entities to provide disclosures in their financial statements that enable users to evaluate the significance of financial instruments to the entity's financial position and performance. It also requires that entities disclose the nature and extent of risks arising from financial instruments and how the entity manages those risks.

Section 3863 – Financial Instruments – Presentation

This standard establishes standards for presentation of financial instruments and non-financial derivatives and deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset.

Also on December 1, 2006, Canada’s Accounting Standards Board issued a new standard regarding Capital Disclosure requiring the disclosure of information about an entity’s objectives, policies and processes for managing capital; quantitative data about what the entity regards as capital; whether the entity has complied with any externally imposed capital requirements; and if it has not complied, the consequences of such non-compliance. This standard also has an implementation date for annual and interim financial statements beginning on or after October 1, 2007.

Subsequent to June 30, 2007, new Canadian interpretive guidance has been released for the presentation and disclosure of standardized distributable cash in income trusts and other flow-through entities. This guidance is effective beginning in the Third Quarter of 2007.

OPERATIONAL AND OTHER BUSINESS RISKS

Our financial and operating performance is subject to risks and uncertainties which include, but are not limited to: oil and natural gas operations, refinery and petroleum marketing operations, reserve estimates, commodity prices, ability to obtain financing, environmental, health and safety risk, regulatory risk, disruptions in the supply of crude oil and delivery of refined products, employee relations, and other risks specifically discussed previously in this MD&A. We intend to continue executing our business plan to create value for Unitholders by paying stable monthly distributions and increasing the net asset value per trust unit. All of our risk management activities are carried out under policies approved by the Board of Directors of Harvest Operations, and are intended to mitigate the risks noted above as follows:

Operation of oil and natural gas properties:

Applying a proactive management approach to our properties;

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

Operation of a refining and petroleum marketing business

Maintaining a proactive approach to managing the supply of feedstock and sale of refined products (including the Supply and Offtake Agreement with Vitol Refining S.A.) to ensure the continuity of supply of crude oil to the refinery and the delivery of refined products from the refinery;

Allocating sufficient resources to ensure good relations are maintained with our non-unionized and unionized work force; and

Selectively adding experienced refining management to further strengthen our "in-house" management team, particularly a new leader for our refinery operations to replace the current President, Refinery Manager of North Atlantic who has committed to an orderly transition.

Estimates of the quantity of recoverable reserves:

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 exposures:

Maintaining a 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 of Harvest Operations action to be taken;

Executing risk management contracts with a portfolio of credit-worthy counterparties;

Maintaining a low cost structure to maximize product netbacks; and

Limiting the period of exposure to price fluctuations between crude oil prices and product prices by entering into contracts such that crude oil feedstock will be priced based on the price at or near the time of delivery to the refinery, which may be as much as 24 days subsequent to the time the feedstock is initially loaded onto the shipping vessel. Thereby, minimizing the time between the pricing of the feedstock and the refined products with the objective of maintaining margins.

Financial risk:

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

Retaining a portion of cash flows to finance capital expenditures and future property acquisitions; and

Carrying adequate insurance to cover property and business interruption losses.

Environmental, health and safety risks:

Adhering to our safety programs and keeping abreast of current industry practices for both the oil and natural gas industry as well as the refining industry; and

Committing funds on an ongoing basis toward the remediation of potential environmental issues.

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

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 to assist in dealing with the changing regulatory environment.

CHANGES IN REGULATORY ENVIRONMENT

The Government of Alberta has announced its intention to examine Alberta’s royalty and tax regime and in February 2007, appointed an independent panel of experts to conduct a review of all aspects of the royalty system including conventional oil and gas, oil sands and coalbed methane. A final report with recommendations is expected to be presented to the Government of Alberta by August 31, 2007. It would be premature to assess the impact of the initiative, if any, on our financial statements at this time.

In 2002, the Government of Canada ratified the Kyoto Protocol which calls for Canada to reduce its greenhouse gas emissions to specified levels. On April 26, 2007, the Government of Canada released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan") which includes a regulatory framework for air emissions. This Action Plan is to regulate the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. Meanwhile, the Government of Alberta has introduced the Climate Change and Emissions Management Amendment Act which intends to reduce greenhouse gas emissions intensity from large emitting facilities. Giving the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to assess the impact of the requirements on our operations and financial performance.

NON-GAAP MEASURES

Throughout this MD&A we have referred to certain measures of financial performance that are not specifically defined under Canadian GAAP. Specifically, we use Funds From Operations as cash provided by operating activities before changes in non-cash working capital, settlement of asset retirement obligations and one time transaction costs. Funds From Operations as presented is not intended to represent an alternative to net earnings, cash provided by operating activities or other measures of financial performance calculated in accordance with Canadian GAAP. Management uses Funds From Operations 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 total distributions to total Funds From Operations. 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 management contracts. Cash G&A are G&A expenses excluding the effect of our unit based compensation plans. Gross Margin is commonly used in the refining industry to reflect the net cash received from the sale of refined products after considering the cost to purchase the feedstock and is calculated by deducting purchased products for resale and processing from total revenue. Earnings From Operations is also commonly used in the petroleum and natural gas and refining industries to reflect operating results before items not directly related to operations.

For the three and six months ended June 30, 2007 and 2006, Funds From Operations is reconciled to its closest GAAP measure, cash provided by operating activities, as follows:

		Three Months Ended June 30				Six Months Ended June 30
(000s)		2007		2006		2007		2006

Funds From Operations	$	244,461	$	147,010	$	458,402	$	247,981
Cash Viking transaction costs		-		(670)		-		(5,742)
Settlement of asset retirement obligations		(2,268)		(625)		(4,388)		(1,743)
Changes in non-cash working capital		9,025		(10,134)		(91,748)		(16,751)
Cash provided by operating activities	$	251,218	$	135,581	$	362,266	$	223,745

FORWARD-LOOKING INFORMATION

This MD&A highlights significant business results and statistics from our consolidated financial statements for the three and six months ended June 30, 2007 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; risks associated with refinery 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, refinery throughput volumes, royalty rates, operating costs, commodity prices, administrative costs, commodity price risk management activity, acquisitions and dispositions, capital spending, reserve estimates, distributions, access to credit facilities, capital taxes, income taxes, Funds 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 we 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.

ADDITIONAL INFORMATION

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.

Harvest Energy Trust (HTE) Inactive 6-KHarvest Energy Trust Announces Second Quarter 2007 Financial and Operating Results