Harvest Energy Trust (HTE) 6-K Current report (foreign)

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 month periods ended March 31, 2007 and 2006. The information and opinions concerning our future outlook are based on information available at May 8, 2007.

When reviewing our 2007 results and comparing them to 2006, readers should be cognizant that the 2007 results include three 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 two months of operations from our acquisition of Viking. This significantly impacts the comparability of our operations and financial results for the three month period ended March 31, 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 Cash Flow, Operating Income, 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 – First Quarter 2007

• Cash Flow of $213.9 million for the three month period ended March 31, 2007, an increase of $113.0 million over the prior year primarily due to our acquisitions in 2006 and continued strength in oil prices.
• Operating Cash Flow from North Atlantic of $94.7 million, reflecting the combined benefits of robust refining margins and solid refinery operating performance as throughput averaged 113,711 bbls/d.

• Operating Cash Flow from our petroleum and natural gas operations of $158.4 million with production averaging 62,024 boe/d, a narrowing of oil price differentials and reduced losses on the settlement of price risk management contracts.

• Completed a $148.5 million capital program in western Canada, drilling 92 gross petroleum and natural gas wells with a success rate of 97% focusing on oil producing opportunities resulting in an exit production rate of approximately 66,000 boe/d.

• Maintained our monthly distributions of $0.38 per trust unit through the quarter resulting in a Payout Ratio of 68% and announced the continuation of a $0.38 per trust unit monthly distribution for the second quarter of 2007.
• Increased our Three Year Extendible Revolving Credit Facility by $200 million to $1.6 billion and extended the maturity date on $1,535 million to April 2010.
• Raised $357.4 million with the issuance of 6,146,750 trust units and $230 million principal amount of convertible debentures in February 2007, bolstering our balance sheet.
   

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SELECTED INFORMATION

The table below provides a summary of our financial and operating results for the three month periods ended March 31, 2007 and 2006. Detailed commentary on individual items within this table is provided elsewhere in this MD&A.

		Three Month Period Ended March 31
($000s except where noted)
		2007		2006	Change
Revenue, net(1)	1,011,094			131,432	669%
Cash Flow(2)		213,941		100,971	112%
Per trust unit, basic(2)	$	1.68	$	1.23	37%
Per trust unit, diluted(2)	$	1.52	$	1.22	25%
Net income (loss)		69,850		(33,937)	306%
Per trust unit, basic	$	0.55	$	(0.41)	234%
Per trust unit, diluted	$	0.55	$	(0.41)	234%
Distributions declared		145,270		94,812	53%
Distributions declared, per trust unit	$	1.14	$	1.11	3%
Payout ratio (2)		68%		94%	(26%)
Bank debt	1,363,222			201,652	576%
Senior debt		279,612		292,000	(4%)
Convertible Debentures		793,184		242,244	227%
Total long-term financial liabilities	2,436,018			735,896	231%
Total assets	5,800,346		3,470,653		67%
PETROLEUM AND NATURAL GAS OPERATIONS
Daily Production
Light to medium oil (bbl/d)		27,034		23,900	13%
Heavy oil (bbl/d)		15,614		15,182	3%
Natural gas liquids (bbl/d)		2,496		1,709	46%
Natural gas (mcf/d)		101,282		73,337	38%
Total daily sales volumes (boe/d)		62,024		53,014	17%
Cash capital expenditures		148,487		103,239	44%
REFINING AND MARKETING OPERATIONS
Average daily throughput (bbl/d)		113,711		-	n/a
Aggregate throughput (mbbl)		10,234		-	n/a
Cash capital expenditures		4,883		-	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.

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REVIEW OF FIRST QUARTER PERFORMANCE

Harvest is a fully 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 first quarter of 2007, we generated Cash Flows of $213.9 million ($1.68 per basic trust unit) compared to Cash Flows of $101.0 million ($1.23 per basic trust unit) in the first quarter of 2006. This $113.0 million increase in Cash Flow is predominately attributed to the incremental impact of the North Atlantic acquisition and to a lesser extent, the impact of the Birchill acquisition. During the first quarter of 2007, our petroleum and natural gas operations benefited from the significant narrowing 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 nominal loss this quarter as the floor price of our oil price contracts averaged US$55.67 as compared to a floor price of US$42.11 and a $9.2 million loss in the first quarter of 2006.

During the first three months of 2007, the North Atlantic refinery operated at near capacity reporting 113,711 bbls/d of throughput and benefited from a gross margin (or crack spread) of US$11.85 per bbl. At the end of November 2006, an extended turnaround of the Refinery was completed and the throughput during the first quarter of 2007 reflects minimal operating disruptions and yields as expected. North Atlantic’s crack spread in the first quarter improved by approximately 27% over the 73 days included in our fourth quarter of 2006 while the "2-1-1 Crack Spread" benchmark improved by 37% over the same period. As expected, North Atlantic’s gross margin did not enjoy the full benefit of improving crack spreads as the narrowing of the price differential on the medium gravity sour crude oil processed by the Refinery increased our costs relative to the WTI benchmark price and the cost of vacuum gas oil also increased. Furthermore, our Refinery produces 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 first quarter of 2007 was 62,024 boe/d and includes three months of production from the assets acquired in the Viking and Birchill acquisitions compared to the first quarter of 2006 which includes only two months of the Viking acquisition. Our first quarter production is lower than our 2006 year end exit production of 65,023 boe/d, as it reflects reduced volumes from the Hay River property which is a "winter access only" property that requires substantially all drilling and maintenance activity to be performed when the ground is frozen. During the first quarter, the prices realized on our production have improved by 27% for heavy oil and 11% for light to medium oil reflecting the narrowing of quality differentials as the WTI benchmark price fell by 8% on a year-over-year basis. Our price for natural gas was essentially unchanged. Our gross revenues during the first quarter of 2007 were up 30% before the impact of price risk management and royalties and our net revenues of $226.5 million increased by 73% after deducting both realized and unrealized price risk management losses and royalties. First quarter 2007 operating costs were $72.3 million, which is $22.2 million higher than the first quarter of the prior year. This increase is primarily due to the impact of the Viking and Birchill acquisitions, but also reflects increased workover and repairs and maintenance costs. On a per unit basis, operating cost increases are magnified, as many of the workover activities temporarily shut-in production. Overall, our operating netback during the first three months of 2007 was $29.76 per boe compared to $25.30 in the comparative period of 2006, an 18% improvement.

Distributions declared during the first quarter of 2007 totaled $1.14 per trust unit resulting in our payout ratio being 68% of Cash Flow compared to $1.11 and 94% (before deducting $5.1 million of cash transaction costs relating to the Viking acquisition) in the prior year. For the first quarter of 2007, the participation in our distribution reinvestment plan was approximately 30% while in the comparative period, the participation rate was approximately 43%. Our DRIP plan 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.

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In February 2007, we issued $230 million principal amount of convertible debentures and 6,146,750 trust units at a price of $23.40 per trust unit for net proceeds of $357.4 million. The net proceeds from this financing were used to repay the remaining $289.7 million on the Senior Secured Bridge Facility with the remaining $67.7 million applied to the drawn portion of our Three Year Extendible Revolving Credit Facility.

Subsequent to the end of the first quarter, we requested an extension of the maturity date from March 2009 to April 2010 for our $1.4 billion Three Year Extendible Revolving Credit Facility and sought to increase the facility from $1.4 billion to $1.6 billion. With our lenders consent, we have now upsized our facility to $1.6 billion and extended the maturity date to April 2010 on $1,535 million of the facility with one lender representing $65 million retaining the March 2009 maturity date.

Business Segments

With 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 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 a wholesale and home heating business. The following table presents selected financial information for our two business segments:

	Three Month Period Ended
		2007		2006
	Petroleum and	Refining and	Total	Total(3)
(in 000’s of Canadian dollars)	natural gas	marketing
Revenue(1)	227,049	784,045	1,011,094	131,432
Operating income(2)	27,434	75,356	102,790	(23,164)
Capital expenditures	148,487	4,883	153,370	103,239
Total assets	4,071,277	1,729,069	5,800,346	3,470,653
(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 month period ended March 31, 2006, Harvest’s operations consisted of only petroleum and natural gas operations.

PETROLEUM AND NATURAL GAS OPERATIONS

Financial and Operating Results
Our acquisitions of Viking in February 2006 and Birchill in August 2006 significantly impact the comparability of our first quarter results in 2007 with the results of the prior year. Throughout the first quarter of 2007, our production mix was approximately 48% light to medium oil and natural gas liquids, 25% heavy oil and 27% natural gas with our core areas of production located in Alberta, Saskatchewan and northeastern British Columbia.

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The following summarizes the financial and operating information of our petroleum and natural gas operations for the three month periods ended March 31, 2007 and 2006:

		Three Month Period ended March 31
(in 000’s of Canadian dollars except as noted below)		2007	2006	Change
Revenues	$	291,116	$ 224,275	30%
Royalties		(49,649)	(43,115)	15%
Realized losses on price risk management contracts(1)		(797)	(9,208)	(91%)
Unrealized losses on price risk management contracts		(14,121)	(40,997)	(66%)
Net revenues excluding realized losses on electric power fixed price contracts		226,549	130,955	73%
Operating expenses		72,296	50,094	44%
Realized gains on electric power fixed price contracts		(500)	(477)	5%
Net operating expenses		71,796	49,617	45%
General and administrative expenses		10,104	5,812	74%
Transportation and marketing		2,812	1,623	73%
Transaction costs		-	11,742	n/a
Depreciation, depletion, amortization and accretion		114,403	85,325	34%
Operating Income (Loss)(2)		27,434	(23,164)	218%
Cash capital expenditures (excluding acquisitions)		148,487	103,239	44%
Property and business acquisitions, net		30,953	23,382	32%
Daily sales volumes
Light to medium oil (bbl/d)		27,034	23,900	13%
Heavy oil (bbl/d)		15,614	15,182	3%
Natural gas liquids (bbl/d)		2,496	1,709	46%
Natural gas (mcf/d)		101,282	73,337	38%
Total (boe/d)		62,024	53,014	17%
(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 Month Period ended March 31
Benchmarks	2007	2006	Change
West Texas Intermediate crude oil (US$ per barrel)	58.16	63.48	(8%)
Edmonton light crude oil ($ per barrel)	67.11	68.96	(3%)
Bow River blend crude oil ($ per barrel)	50.04	39.98	25%
AECO natural gas daily ($ per mcf)	7.40	7.52	(2%)
AECO natural gas monthly ($ per mcf)	7.45	9.27	(20%)
Canadian / U.S. dollar exchange rate	0.854	0.866	(1%)

The West Texas Intermediate ("WTI") crude oil price was 8% lower during the three month period ended March 31, 2007 than in the prior year. The reduction in the average WTI price was not fully reflected in the Edmonton light crude oil ("Edmonton Par") nor the Bow River blend crude oil benchmark prices which were 3% lower and 25% higher, respectively. During the first quarter of 2007, there was a significant narrowing in the differentials between these Canadian benchmark  prices and the WTI price as compared to the prior year. This narrowing of the Edmonton Par to WTI differential is primarily attributed to strong demand for western Canadian light crude in 2007 as compared to 2006 when demand weakened due to operating disruptions at several light oil refineries in central Canada. The Canadian/US dollar exchange rate was relatively unchanged between the first quarter of 2007 and the first quarter of 2006 but offset the lower WTI price by approximately $1.00 relative to the Edmonton Par price.

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For the three month period ended March 31, 2007, prices for heavy crude oil of $50.04 were 25% higher than in 2006 with Bow River differentials narrowing to 25.4% of Edmonton Par for the three month period ended March 31, 2007 compared to 42.0% in 2006. In the prior year, heavy oil inventory levels were higher than in 2007 and pipeline capacity limited the delivery of heavy crude to the US markets. As shown below, heavy oil differentials continue to narrow as compared to 2006 and 2005.

	2007	2006				2005
Differential Benchmarks	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Bow River Blend differential to
Edmonton Par	25.4%	30.3%	25.8%	22.9%	42.0%	40.0%	28.2%	39.6%

Realized Commodity Prices

The following table provides a breakdown of our average prices by product and our overall net realized price before and after realized losses on price risk management contracts for the three month periods ended March 31, 2007 and 2006.

	Three Month Period ended March 31
	2007	2006	Change
Light to medium oil ($/bbl)	58.90	53.06	11%
Heavy oil ($/bbl)	44.54	35.12	27%
Natural gas liquids ($/bbl)	52.78	56.69	(7%)
Natural gas ($/mcf)	8.05	8.10	(1%)
Average realized price ($/boe)	52.15	47.01	11%
Realized price risk management losses ($/boe)(1)	(0.14)	(1.93)	(93%)
Net realized price ($/boe)	52.01	45.08	15%
(1)    Includes amounts realized on WTI, heavy oil price differential and foreign exchange contracts and excludes amounts realized on electric power fixed price contracts.

For the three months ended March 31, 2007, our average realized price was 11% higher before the realized losses on our price risk management contracts and 15% higher after deducting the realized losses on these contracts as compared to the prior year. Our realized price for oil in the current quarter averaged $53.64 before losses on crude oil price risk management contracts as compared to $46.09 in the first quarter of 2006, representing a 16% increase over the prior year. The increase in our average realized oil price during the first quarter is primarily due to the Bow River differential to Edmonton Par improving from a 42.0% discount in the prior year to a 25.4% discount in the current year. As 35% of our total production is priced off of the Bow River stream, it was expected that our average realized oil price increase would be greater than the change in the Edmonton Par price. During the first three months of 2007, the gains realized on the settlement of our crude oil price risk management contracts aggregated to $290,000 as compared to losses of $9.6 million in the first three months of 2006 as the floor price of our contracts has increased to US$55.67 compared to US$42.11 in the prior year.

In the first quarter of 2007, the realized price of our light to medium oil sales increased 11% compared to the prior year while the Edmonton Par price decreased 3% over the same period. Improved quality differentials for light to medium oil production realized in 2007 relative to the Edmonton Par benchmark price is the primary reason for our higher than expected realized price.

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Our realized heavy oil price for the first quarter of 2007 of $44.54 was 27% higher than in the prior year primarily due to the significant narrowing in the Bow River differential to Edmonton Par noted above. The majority of our heavy oil production is priced off of the Bow River benchmark price.

During the three months ended March 31, 2007, our realized natural gas price of $8.05 was essentially unchanged (down by 1% compared to the prior year), reflecting the modest 2% decrease in the AECO daily price. During the first quarter of 2007, approximately 60% of our natural gas sales were priced off the AECO daily benchmark, approximately 30% sold off the AECO monthly benchmark with the remainder sold to aggregators. During the first quarter of 2007, the realized gain on the settlement of our natural gas price risk management contracts totaled $161,000 as compared to a $239,000 gain in the prior year.

Sales Volumes

The average daily sales volumes by product were as follows:

	Three Month Period ended March 31
	2007		2006
	Volume	Weighting	Volume	Weighting	% Volume Change
Light to medium oil (bbl/d)(1)	27,034	44%	23,900	45%	13%
Heavy oil (bbl/d)	15,614	25%	15,182	29%	3%
Total oil (bbl/d)	42,648	69%	39,082	74%	9%
Natural gas liquids (bbl/d)	2,496	4%	1,709	3%	46%
Total liquids (bbl/d)	45,144	73%	40,791	77%	11%
Natural gas (mcf/d)	101,282	27%	73,337	23%	38%
Total oil equivalent (boe/d)	62,024	100%	53,014	100%	17%
(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 24o (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 March 31, 2007, average production was higher than in the prior year primarily due to the acquisition of Viking in February of 2006 and the acquisition of Birchill in the third quarter of 2006.

Light to medium oil production is 3,134 bbl/d higher compared to the prior year primarily due to one month’s incremental production related to the acquisition of Viking (3,013 bbl/d) and a further three months of incremental production attributed to the acquisition of Birchill (1,050 bbl/d) partially offset by natural decline in production. In both years, our Hay River production has been disrupted as a result of significant routine maintenance turnarounds at production facilities and an extensive drilling program in this area where access is limited to winter only. In 2007, our Hay River production averaged 5,451 bbl/d for the first quarter, with our exit production rate at the end of March 2007 of approximately 6,800 bbl/d attributed to the success of the drilling program and a return to normal operations in the area.

Heavy oil production for the three months ended March 31, 2007 of 15,614 bbl/d remained relatively consistent with the prior year as approximately 3,000 bbl/d of incremental volumes from two heavy oil acquisitions (one in the fourth quarter of 2006 and another at the end of February 2007) was more than sufficient to offset the natural decline in our heavy oil properties. As in 2006, our production at Suffield during the first quarter of 2007 was 593 bbl/d below expectations due to "military lockdowns" and disruptions in water handling.

Natural gas production for the three month period ended March 31, 2007 of 101,282 mcf/d is 27,945 mcf/d higher than the prior year primarily due to the acquisition of Birchill in August 2006 adding approximately 16,500 mcf/d of incremental natural gas production plus a full three months of natural gas production from the Viking acquisition completed in February 2006. These acquisition related increases are partially offset by higher than expected production declines in the Markerville/Sylvan Lake area from wells drilled in 2006 where the initial flush production has stabilized. With much of our planned drilling directed to oil related prospects, our natural gas production will benefit primarily from the re-completion of existing wells and the tie in of wells drilled in 2006.

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Revenues
	Three Month Period ended March 31
(000s)		2007		2006	Change
Light to medium oil sales	$	143,305	$	114,123	26%
Heavy oil sales		62,585		47,987	30%
Natural gas sales		73,370		53,444	37%
Natural gas liquids sales and other		11,856		8,721	36%
Total sales revenue		291,116		224,275	30%
Realized risk management contract losses(1)		(797)		(9,208)	(91%)
Total revenues including realized risk management contract losses		290,319		215,067	35%
Realized gains on electric power price risk management contracts		500		477	5%
Unrealized losses on price risk management contracts		(14,121)		(40,997)	(66%)
Net Revenues, before royalties		276,698		174,547	59%
Royalties		(49,649)		(43,115)	15%
Net Revenues	$	227,049	$	131,432	73%
(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. Light to medium oil sales revenue for the three month period ended March 31, 2007 was $29.2 million (or 26%) higher than the comparative period, comprised of a $14.2 million favourable price variance resulting from the 11% increase in price and a $15.0 million favourable volume variance. The favourable volume variances over the prior year are primarily due to the acquisitions of Viking and Birchill in 2006 as well as the results of our drilling program which has focused on light to medium oil production.

Heavy oil sales revenue for the first quarter of 2007 increased $14.6 million (or 30%) compared to the same period in the prior year due primarily due to a favourable price variance of $13.2 million coupled with a favourable volume variance of $1.4 million. The significant narrowing of heavy oil differentials resulted in higher realized prices on our heavy oil. Our heavy oil production was essentially unchanged at 15,614 bbls/d for the first quarter of 2007 as compared to 15,182 in the prior year with the current period benefiting from an incremental month’s production from the Viking assets, the two recent heavy oil acquisitions and new wells drilled in Hayter and Suffield in 2006 offset by natural declines and higher water cuts.

Natural gas sales revenue increased by $19.9 million (or 37%) for the three month period ended March 31, 2007 over the prior year primarily due to a favourable volume variance of $20.4 million offset by a modest $500,000 unfavourable price variance. Natural gas prices were essentially unchanged during the current year compared to the prior year with the favourable volume variance entirely attributed to the incremental gas production from the properties acquired in the Viking and Birchill acquisitions in 2006.

During the first quarter of 2007, our natural gas liquids and other sales increased by $3.1 million (or 36%) compared to the prior year. This increase is due to a $4.0 million favourable volume variance offset by a $0.9 million unfavourable price variance with the volume variance attributed to the same natural gas properties giving rise to our favourable natural gas volume variance.

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Price Risk Management Contracts

Details of our price risk management contracts outstanding at March 31, 2007 are included in Note 15 of our interim consolidated financial statements for the three month period ended March 31, 2007 filed on SEDAR at www.sedar.com. The table below provides a summary of net gains and losses on our price risk management contracts during the respective periods:

	Three Month Period ended March 31
	2007										2006
(000s)	Oil		Gas		Currency		Electricity		Total		Total
Realized (losses) / gains on price risk
management contracts	$	290	$	161	$	(1,248)	$	500	$	(297)	$	(8,731)
Unrealized (losses) / gains on price
risk management contracts		(12,241)		(2,815)		1,362		(427)		(14,121)		(41,297)
Amortization of deferred gains
relating to risk management
contracts		-		-		-		-		-		300
Total (losses) / gains on risk
management contracts	$	(11,951)	$	(2,654)	$	114	$	73	$	(14,418)	$	(49,728)

Our total realized loss on price risk management contracts was $297,000 for the three month period ended March 31, 2007 compared to $8.7 million for the same period in 2006, primarily the result of our oil price contracts being settled with a slight gain in the current year as compared to a loss of $9.6 million in the prior year.

Our realized gains on oil price contracts for the three months ended March 31, 2007 of $290,000 was a substantial improvement from the $9.6 million loss realized during the first quarter of the prior year. In the first 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 for the three months ended March 31, 2006. As compared to 2006, the WTI price during the first quarter of 2007 averaged US$58.16, a decrease of US$5.32 from US$63.48 in the prior year. The elimination of losses on our oil price risk management contracts is the result of the higher contracted floor prices and the lower WTI price. We also had heavy oil price differential contracts protecting the differential on 1,000 bbl/d at 27.7% of WTI for the first three months of 2007 which was relatively close to the average heavy oil differential of 26.5% of WTI for the quarter. We have not entered into any crude oil price risk management contracts during the first quarter of 2007 as in light of our acquisition of the North Atlantic refinery we have concluded that the contracting for price protection on refined products is preferred to price protection on crude oil sales.

To protect against the possibility of soft natural gas prices, we entered into one natural gas price risk management contract for the period from November 2006 through March 2007 for 25,000 GJ/d with a floor price of $7.00 and a price cap of $12.50 and a second contract for the period from June 2006 to March 2007 for 25,000 GJ/d with a floor price of $5.00 and a price cap of $13.55. During the first quarter of 2007, the floor price of $7.00 on 25,000 GJ/d resulted in a $161,000 gain. 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

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During the first quarter 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 $1.3 million of losses settling the contracts as the exchange rate averaged approximately $0.85 during the quarter. Offsetting this loss was a realized foreign exchange gain of $0.5 million resulting from our participation in an oil sales contract which entitles us to elect on a monthly basis to accept settlement of the prior month’s sales proceeds in US currency or to fix the currency exchange rate for a Canadian dollar settlement. For the balance of 2007, we have entered into contracts to fix the currency exchange rate on US$8,750,000 per month at an average rate of approximately $0.89.

We continue to recognize gains from our electric power price risk management contracts amounting to $500,000 during the first quarter of 2007 compared to $477,000 in the prior year. We enter into these contracts to provide protection from rising electric power prices. During the first quarter of 2007, Alberta’s electric power price averaged $63.62 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 first quarter of 2007, we recorded an unrealized net loss on our price risk management contracts of $14.1 million, and at March 31, 2007, our price risk management contracts had an unrealized mark-to-market deficiency of $16.0 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 month period ended March 31, 2007, our net royalties as a percentage of gross revenue were 17.1% (19.2% - three months ended March 31, 2006) and aggregated to $49.6 million ($43.1 million – three months ended March 31, 2006). The decrease in the royalty rate is attributable to lower freehold mineral taxes and a lower crown royalty rate on natural gas.

Operating Expenses
	Three Month Period ended March 31
									Per BOE
($000s)		2007		Per BOE		2006		Per BOE	Change
Operating expense
Power	$	13,773	$	2.47	$	12,028	$	2.52	(2%)
Workovers		17,162		3.07		8,392		1.76	74%
Repairs and maintenance		13,634		2.44		5,449		1.14	114%
Labour – internal		3,618		0.65		3,278		0.69	(6%)
Processing fees		8,168		1.46		3,933		0.82	78%
Fuel		1,930		0.35		3,887		0.81	(57%)
Labour – external		3,960		0.71		2,029		0.43	65%
Land leases and property tax		3,126		0.56		2,995		0.63	(11%)
Other		6,925		1.24		8,103		1.70	(27%)
Total operating expense		72,296		12.95		50,094		10.50	23%
Realized gains on electric power price risk management contracts		(500)		(0.09)		(477)		(0.10)	(10%)
Net operating expense	$	71,796	$	12.86	$	49,617	$	10.40	24%
Transportation and marketing expense	$	2,812	$	0.50	$	1,623	$	0.34	47%

Total operating expense increased by $22.2 million to $72.3 million for the three month period ended March 31, 2007 compared to the prior period. A significant portion of this increase is attributed to the additional production from the incremental month of activity for the Viking assets acquired in February 2006 and the activity associated with the assets from the Birchill acquisition completed in August 2006. However, the high demand for oilfield services leading to higher costs for well servicing, workovers, labour and well maintenance continues.

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On a per barrel basis our operating costs have increased to $12.95 per boe, a 23% increase over 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 quarter 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 do 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 operating expenses benefit from our cost reduction initiatives such as the water disposal and fluid handling project in Suffield where we incurred approximately $13 million in capital expenditures in 2006 to lower electric power costs required to operate high water cut wells.

Our transportation and marketing expense of $2.8 million for the three months ended March 31, 2007 is $1.2 million higher (73%) than in the prior period. 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 crude oil to pipeline receipt points. As compared to the prior year, our natural gas production in the first quarter of 2007 of 101,282 mcf/d is 38% higher substantially related to the incremental natural gas production associated with our acquisition of Viking and Birchill in 2006 which has contributed to higher transportations costs. In late 2006, 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. This contributes to the increase in our transportation expense, but is more than offset by increases on realized prices.

Electric power costs represented approximately 19% of our total operating costs during the three months ended March 31, 2007 compared to approximately 24% in the prior year. Aggregate power costs have increased 15% to $13.8 million in the current quarter compared to $12.0 million in the comparative quarter. For the three months ended March 31, 2007, electric power prices per MWh were 12% higher than in the prior year, however, the impact of higher prices was offset on a per boe basis with lower consumption and a 17% increase in production. Our electric power price risk management contracts have resulted in a lower electric power cost on a per boe basis in the first quarter of both 2007 and 2006. The following table details the electric power costs per boe before and after the impact of our price risk management program.

	Three Month Period ended March 31
(per boe)		2007		2006	Change
Electric power costs	$	2.47	$	2.52	(2%)
Realized gains on electricity risk management contracts		(0.09)		(0.10)	(10%)
Net electric power costs	$	2.38	$	2.42	(2%)
Alberta Power Pool electricity price (per MWh)	$	63.62	$	56.96	12%

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 Month Period ended March 31
(per boe)		2007		2006
Revenues	$	52.15	$	47.01
Realized loss on risk management contracts(1)		(0.14)		(1.93)
Royalties		(8.89)		(9.04)
Operating expense(2)		(12.86)		(10.40)
Transportation and marketing expense		(0.50)		(0.34)
Operating netback(3)	$	29.76	$	25.30

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

(2) Includes realized gains on electric power price risk management contracts of $0.09 per boe and $0.10 per boe for the three month periods ended March 31, 2007 and 2006

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

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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 month period ended March 31, 2007, our operating netback of $29.76 is $4.46 per boe higher and an 18% improvement over the prior year. Higher oil prices in the current quarter compared to the first quarter in the prior year resulted in increased revenue of $5.14 per boe while reduced losses realized on our price risk management program of $1.79 per boe are not sufficient to fully offset an increase of $2.46 per boe in operating costs. Marginally lower royalties offset higher transportation costs.

General and Administrative ("G&A") Expense
	Three Month Period ended March 31
(000s except per boe)		2007		2006	Change
Cash G&A(1)	$	7,205	$	6,053	19%
Unit based compensation expense		2,899		(241)	1,303%
Total G&A	$	10,104	$	5,812	74%
Cash G&A per boe ($/boe)		1.29		1.27	2%

(1) Cash G&A excludes the impact of our unit based compensation expense and for the three months ended March 31, 2006 $3.1 million of one time transaction costs.

For the three months ended March 31, 2007, Cash G&A costs increased by $1.2 million (or 19%) compared to the same period in 2006, which is attributed mainly to increased staffing levels with our integration of the staff from our acquisitions of Viking and Birchill adding more than 100 employees. Approximately 86% 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. The remainder of the increases for the three month period ended March 31, 2007 compared to 2006 are due to higher office rental costs required for the additional staff and increased travel costs related to the refinery acquisition.

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 March 31, 2007 was $2.9 million. Our opening trust unit market price was $26.23 at January 1, 2007 and at March 31, 2007, our trust unit price had increased to $28.57. As a result, we have recorded an expense of $2.4 million on unexercised UARs for the three month period ended March 31, 2007. Our total unit based compensation expense has increased $3.1 million over the first quarter of the prior year after considering that $8.6 million of unit based compensation expense incurred in the first three months of 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 Month Period ended March 31
(000s except per boe)		2007		2006	Change
Depletion, depreciation and amortization	$	105,896	$	77,395	37%
Depletion of capitalized asset retirement costs		4,061		4,282	(5%)
Accretion on asset retirement obligation		4,446		3,648	22%
Total depletion, depreciation, amortization and accretion	$	114,403	$	85,325	34%
Per boe ($/boe)		20.49		17.88	15%

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Our overall depletion, depreciation, amortization and accretion ("DDA&A") expense for the three months ended March 31, 2007 is $29.1 million higher as compared to the prior year. Of this, $14.5 million is due to the incremental production from the merger with Viking in early 2006 and the acquisition of Birchill in August of 2006. The remaining $14.6 million of the 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 Month Period ended March 31
(000s)		2007		2006
Land and undeveloped lease rentals	$	160	$	2,087
Geological and geophysical		4,014		1,000
Drilling and completion		78,284		66,516
Well equipment, pipelines and facilities		63,345		29,884
Capitalized G&A expenses		2,553		3,941
Furniture, leaseholds and office equipment		131		(189)
Development capital expenditures excluding acquisitions		148,487		103,239
Non-cash capital additions		415		390
Total development capital expenditures excluding acquisitions and non-cash items	$	148,902	$	103,629

During the first three months of 2007 we invested $148.5 million in drilling, operating optimization and enhancement projects compared to $103.2 million in the first quarter of the prior year. Approximately 53% of the 2007 expenditures were directly related to the drilling of 92 gross wells with a success rate of 97% as compared to 82 gross wells in 2006 and a success rate of 98%. As we expect the current strong oil pricing environment to continue, we continued to focus our drilling activity on oil opportunities with 65 of the 92 wells drilled targeting oil prospects.

The following summarizes Harvest’s participation in gross and net wells drilled during the first three months of 2007:

	Total Wells		Successful Wells		Abandoned Wells
Area	Gross1	Net	Gross	Net	Gross	Net
Hay River	31	31.0	31	31.0	-	-
Southeast Saskatchewan	11	11.0	11	11.0	-	-
Red Earth	12	8.5	12	8.5	-	-
Suffield	5	5.0	4	4.0	1	1.0
Lloydminster	6	6.0	6	6.0	-	-
Markerville	5	1.9	5	1.9	-	-
Other Areas	22	9.7	20	9.1	2	0.6
Total	92	73.1	89	71.5	3.0	1.6

⁽¹⁾ Excludes 6 additional wells that we have an overriding royalty interest in.

In Hay River, the area with our most active drilling program, we continue to exploit our large Bluesky oil resource using multi-leg horizontal wells. Favourable weather conditions in November 2006 allowed us to commence the 2007 Hay River drilling program a month earlier than anticipated in this "winter access only" area. In southeast Saskatchewan, we drilled our first horizontal wells into our new light oil discovery at Kenosee as well as drilled infill horizontal wells at Hazelwood. At Red Earth, our drilling focused on infill and step-out wells in the Slave Point oil pool while at Lloydminster and Suffield, we continued with an infill horizontal drilling program.

The $63.3 million of well equipment, pipelines and facilities expenditures includes approximately $15 million relating to a number of initiatives to improve the efficiency of our Hay River operations. These include the construction of an all season road, the installation of natural gas infrastructure and an electrical distribution system. At Cairo, we incurred $3.1 million completing the construction of gathering, compression and processing facilities to tie in natural gas wells drilled in 2006 with production expected to commence in the second quarter of 2007.

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Corporate Acquisition

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.

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 March 31, 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 $5.0 million during the three months ended March 31, 2007. This increase is due to additions resulting from the acquisition of a private corporation, drilling activity during the quarter and accretion expense, offset by actual asset retirement expenditures made during the quarter.

REFINING AND MARKETING OPERATIONS

On October 19, 2006, we completed our acquisition of North Atlantic the principal asset of which is a medium gravity sour crude hydrocracking refinery with a 115,000 bbl/d capacity (the "Refinery") and a marketing division with 64 gas stations, a home heating business and a commercial and wholesale petroleum products business, all located in the province of Newfoundland and Labrador. The Refinery is capable of processing a wide range of crude oils and feedstocks with a sulphur content as high as 3.5% and API gravity in the range of 25° to 40° with its product slate weighted towards high quality diesel fuel, jet fuel, and gasoline that are currently compliant with product specifications (including sulphur, cetane and aromatic content). Approximately 10% of North Atlantic’s refined products are sold in the province of Newfoundland and Labrador with the balance sold in the U.S. east coast markets, primarily Boston and New York City. Through its marketing division, North Atlantic operates a petroleum marketing and distribution business in the province of Newfoundland and Labrador with average daily sales over 11,000 barrels representing approximately a 15% to 20% share of the market. Effective with the closing of this acquisition on October 19, 2006, the operating results of North Atlantic are included in the operations of Harvest with segmented reporting for each of the petroleum and natural gas operations in western Canada and the refining and marketing business in the province of Newfoundland and Labrador.

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The following summarizes the North Atlantic financial and operational information for the three month period ended March 31, 2007 compared to the period from October 19, 2006 to December 31, 2006:

(in 000’s of Canadian dollars except as noted below)	Three Month	October 19, 2006
	Period ended	to
	March 31, 2007	December 31, 2006
Revenues	784,045	460,359
Purchased products for resale and processing	632,296	386,014
Gross Margin(1)	151,749	74,345
Costs and expenses
Operating expense	25,661	18,378
Purchased energy expense	24,000	15,685
Marketing expense	7,343	5,060
Depreciation and amortization expense	19,389	15,482
Operating income(1)	75,356	19,740
Cash capital expenditures	4,883	21,411
Feedstock volume (bbl/day)	113,711	86,890
Yield (000’s barrels)
Gasoline and related products	3,310	1,875
Ultra low sulphur diesel	4,213	2,624
Heavy fuel oil	2,745	1,752
Total	10,268	6,251

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

Overview of Refining and Marketing Operations

For the three month period ended March 31, 2007, North Atlantic’s Operating Income and Cash Flow were robust, reflecting strong refining margins as well as near capacity operating performance with no planned nor unplanned disruptions. As compared to the prior period, North Atlantic’s gross margin increased from US$9.32 to US$11.85 per bbl, reflecting the impact of increases in gasoline and heating oil prices, coupled with a slight drop in the WTI price offset by a narrowing of the differential between medium gravity sour crude oil and light sweet crude oil, as well as strengthening prices for heavy fuel oil. North Atlantic’s daily throughput averaged 113,711 bbls/d of crude oil and vacuum gas oil for the first quarter of 2007 as compared to 86,890 bbls/d in the period from October 19, 2006 through December 31, 2006 when the refinery operations were impacted by an extended turnaround, an unplanned disruption with its naphtha hydrotreater and a disruption in electric power service.

Refining Benchmark Prices

An oil refinery is a manufacturing facility that uses crude oil and other feedstocks as a raw material and produces a wide variety of refined products. The actual mix of refined products from a particular refinery varies according to the refinery’s processing units, the specific refining process utilized and the nature of the crude oil feedstock. The refinery processing units generally perform one of three functions: the different types of hydrocarbons in crude oil are separated, the separated hydrocarbons are converted into more desirable or higher value products, or chemicals treat the products to remove unwanted elements and components such as sulphur, nitrogen and metals. Refined products are typically differing grades of gasoline, diesel fuel, jet fuel, furnace oil and heavier fuel oil.

The refining industry has a few benchmark prices from which to assess a particular refinery’s performance. Typically, these benchmarks include prices for refined products such as Reformulated Blendstock for Oxygenate Blending gasoline ("RBOB

15

gasoline") and heating oil. As a benchmark indicator of refining margins, 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 from which to assess the North Atlantic refinery’s performance:

	Three Month	October 19, 2006
	Period ended	to
	March 31, 2007	December 31, 2006
West Texas Intermediate crude oil (US$ per barrel)	58.16	60.44
RBOB gasoline (US$ per barrel/US$ per gallon)	70.77/1.69	66.78/1.59
Heating Oil (US$ per barrel/US$ per gallon)	69.86/1.66	71.82/1.71
2-1-1 Crack Spread (US$ per barrel)	12.14	8.86
Canadian / U.S. dollar exchange rate	0.854	0.883

Although the "2-1-1 Crack Spread" is a typical industry benchmark, the North Atlantic refinery differs in that it also produces 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 (Isomax) unit which is a key unit in the production of gasoline and diesel fuel and this further differentiates the North Atlantic refinery gross margin from the "2-1-1 Crack Spread" benchmark.

North Atlantic’s Refinery Feedstock

The cost and volume of North Atlantic’s crude oil feedstocks were as follows:

	Three Month period ended March 31, 2007			October 19, 2006 to December 31, 2006
	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	422,856	7,002	51.55	305,396	5,372	50.21
Hamaca	96,977	1,664	49.75	28,826	524	48.59
Urals	42,376	730	49.55	-	-	-
Crude Oil Feedstock	562,209	9,396	51.07	334,222	5,896	50.07
Vacuum Gas Oil	57,996	838	59.06	26,645	446	52.77
	620,205	10,234	51.73	360,867	6,342	50.26
Other costs	(819)			6,834
	619,386			367,701

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

During the first quarter of 2007, the Refinery feedstock was comprised of 104,400 bbl/d of medium sour crude oil (approximately 74% Basrah Light from Iraq, 18% Hamaca from Venezula and 8% Urals from Russia) and 9,311 bbl/d of vacuum gas oil compared to 80,767 bbl/d of crude oil and 6,100 bbl/d of vacuum gas oil for the prior period. The price of North Atlantic’s crude oil feedstock averaged US$51.07 for the three months ended March 31, 2007, an increase of US$1.00 compared to the prior period as a US$3.28 narrowing of differentials between its cost of medium gravity sour crude oil feedstock and the sweet light crude oil benchmark more than offset the US$2.28 drop in the WTI benchmark price. Relative to the average price of the WTI benchmark, the medium gravity sour crude purchased by North Atlantic represents a US$7.09 per barrel price differential for the first quarter of 2007 as compared to US$10.37 in the prior period.

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North Atlantic’s Refined Products

Product yields are impacted by the crude oil feedstock as well as refinery performance. During the first quarter of 2007, North Atlantic’s refined product yield was relatively unchanged with approximately 32% gasoline, 41% ultra low sulphur diesel and jet fuel and 27% heavy fuel oil compared to 30%, 42% and 28%, respectively. A summary of North Atlantic’s product yield, pricing and revenue for the three month period ended March 31, 2007 and the prior period are as follows:

	Three Month period ended March 31, 2007			October 19, 2006 to December 31, 2006
	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	273,656	3,310	70.57/1.68	131,643	1,875	62.01/1.48
products
Low & ultra low	360,122	4,213	72.96/1.74	216,435	2,624	72.85/1.73
sulphur diesel & jet fuel
Heavy fuel oil	132,398	2,745	41.16/0.98	78,969	1,752	39.81/0.95
	766,176	10,268		427,047	6,251
Other	(4,838)			7,617
	761,338			434,664
Yield (as a % of Feedstock)		100%			99%
(1) Product prices are based on the sales at the North Atlantic refinery loading docks.

Relative to the benchmark prices, North Atlantic received US$70.57 per bbl (US$1.68 per gallon) for its gasoline during the first quarter of 2007 as compared to US$1.69 per gallon for NYMEX RBOB gasoline and US$72.96 (US$1.74 per gallon) for its ultra low sulphur diesel and jet fuel products compared to US$1.66 for NYMEX heating oil. During the first quarter of 2007, North Atlantic’s gasoline price closely followed the NYMEX reference price (within US$0.01) while its diesel fuel and jet fuel commanded a premium of US$0.08 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 we paid for the Basrah feedstock, the selling price of North Atlantic’s heavy fuel oil resulted in a negative contribution of US$10.39 per barrel and aggregated to approximately $33.4 million for the three month period ended March 31, 2007 compared to US$10.40 per barrel and $20.6 million in the prior period. The heavy fuel oil produced by North Atlantic presents an opportunity to re-configure the Refinery to produce more gasoline and diesel fuel and in March 2007, we announced North Atlantic’s intent to enhance its existing visbreaker unit to more completely upgrade an incremental volume of approximately 1,500 bbl/d of heavy fuel oil into heating oil at an estimated cost of $22 million.

North Atlantic’s 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 the three month period ended March 31, 2007 and from October 19, 2006 to December 31, 2006 are as follows:

	Three Month period ended March 31, 2007			October 19, 2006 to December 31, 2006
(000’s of Canadian dollars)	Refining	Marketing	Total	Refining	Marketing	Total
Sales revenue(1)	761,337	91,290	784,045	434,665	68,099	460,359
Cost of products for	619,386	81,492	632,296	367,701	60,718	386,014
processing and resale(1)
Gross margin(2)	141,951	9,798	151,749	66,964	7,381	74,345
(1) The North Atlantic sales revenue and cost of products for processing and resale are net of inter-segment sales of $68,582,000 reflecting the refined products produced by the Refinery Operations and sold by the Marketing Operations for the three month period ended March 31, 2007 ($42,405,000 for the period from October 19, 2006 to December 31, 2006) (2) These are non-GAAP measures; please refer to "Non-GAAP Measures" in this MD&A.

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During the three months ended March 31, 2007, North Atlantic’s crack spread of $142.0 million is comprised of $162.6 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 $55.3 million) and $15.8 million on the production of gasoline and ultra low sulphur diesel and jet fuel from purchased VGO offset by a $36.4 million negative contribution from the production of heavy fuel oil and other refined products. This compares to gross margin of $67.0 million comprised of $83.7 million (including $47.4 million of heavy sour differential), $9.7 million and $26.4 million, respectively, for the prior period.

Relative to the industry "2-1-1 Crack Spread" benchmark of US$12.14 during the first quarter of 2007 (US$8.86 for the prior period), North Atlantic’s crack spread averaged US$11.85 per barrel of throughput (US$9.32 for the prior period), representing a 27% increase compared to a 37% increase in the "2-1-1 Crack Spread" benchmark. North Atlantic did not fully participate in the "2-1-1 Crack Spread" appreciation as the benefits of processing medium gravity sour crude oil were more than offset by 27% of its production being heavy fuel oil.

The gross margin from North Atlantic’s marketing operations of $9.8 million (up $2.4 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.

Operating Expenses

A summary of North Atlantic’s operating costs for the refinery and marketing operations for the three month period ended March 31, 2007 and from October 19, 2006 to December 31, 2006 are as follows:

	Three Month period ended March 31, 2007			October 19, 2006 to December 31, 2006
(000’s of Canadian dollars)	Refining	Marketing	Total	Refining	Marketing	Total
Operating expense	21,331	4,330	25,661	14,771	3,607	18,378
Purchased energy	24,000	-	24,000	15,685	-	15,685
	45,331	4,330	49,661	30,456	3,607	34,063

The largest component of operating expense is wages and benefits which totaled $14.8 million (approximately 58% of operating expense) while the other significant components were maintenance and repairs costs ($3.4 million), insurance ($1.9 million) and chemicals ($0.8 million) which were all in line with expectations. Other operating expenses are also in line with expectations. Refining operating expenses were $2.08 per barrel during the period which is slightly lower than our expectations of approximately $2.20 to $2.40 per barrel and this is directly attributable to the increased throughput during the quarter.

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 were $2.35 per barrel during the first quarter of 2007 which is slightly higher than our expectations of less than $2.20.

During the first 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 and $6.3 million of "Time Value of Money" charges incurred pursuant to the supply and offtake agreement entered into with Vitol Refining S.A as compared to $0.5 million and $4.6 million, respectively, for the period from October 19, 2006 to December 31, 2006.

Capital Expenditures

During the first quarter of 2007, capital spending totaled $4.9 million and included upgrades to our retail operations, planned maintenance on our feedstock and refined product storage tanks and various sustaining capital and improvement projects.

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Depreciation and Amortization Expense

North Atlantic’s depreciation and amortization expense for the refinery and marketing operations for the three month period ended March 31, 2007 and from October 19, 2006 to December 31, 2006 is as follows:

	Three Month period ended March 31, 2007			October 19, 2006 to December 31, 2006
(000’s of Canadian dollars)	Refining	Marketing	Total	Refining	Marketing	Total
Tangible assets	17,183	495	17,678	13,832	411	14,243
Intangible assets	1,304	407	1,711	1,050	189	1,239
	18,487	902	19,389	14,882	600	15,482

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

Interest Expense
	Three Months ended March 31
(000s)		2007		2006	Change
Interest on short term debt
Bank loan	$	1,170		$ 150	680%
Convertible debentures		646		-	100%
Amortization of deferred finance charges – short term debt		1,811		-	100%
		3,627		150	2,318%
Interest on long-term debt
Bank loan		19,176		1,303	1,372%
Convertible debentures		14,448		3,296	338%
77/8% Senior Notes		6,146		5,724	7%
Amortization of deferred finance charges – long term debt		679		1,434	(53%)
		40,449		11,757	244%
Total interest expense	$	44,076	$	11,907	270%

Interest expense, which includes the amortization of related financing costs, was $32.2 million higher for the three month period ended March 31, 2007 than in the prior year. Of this increase, $18.9 million is due to bank loan interest (both short term and long term) resulting from the significant increase in the drawn amounts on our credit facilities and $11.8 million is related to the $599.7 million increase in the amount of convertible debentures outstanding, both of which were used to finance the acquisition of North Atlantic, and to a lesser extent, the acquisition of Birchill.

During the first quarter of 2007, our short term bank debt consisted of the $289.7 million outstanding under our Senior Secured Bridge Facility which was fully repaid on February 1, 2007 with the net proceeds from our issuance of 6,146,750 trust units and $230 million principal amount of 7.25% Debentures due 2014. The early repayment has also accelerated our expensing of $1.7 million of unamortized commitment fees related to this facility. The interest on the long term portion of our bank loans relates to the interest charges on our Three Year Extendible Revolving Facility at a floating rate based on 75 basis points over bankers’ acceptances for Canadian dollar borrowings and 75 basis points over the London Inter Bank Order Rate for US dollar borrowings. Further details on our credit facilities and the bridge financing are included under "Liquidity and Capital Resources".

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The interest on our convertible debentures totaled $15.1 million during the first quarter of 2007 and is based on the effective yield of the debt component of the convertible debentures. The details of the $851.9 million of convertible debentures outstanding are fully described in Note 11 to the interim consolidated financial statements for the three month period ended March 31, 2007 filed on SEDAR at www.sedar.com. During the quarter, there were $230 million principal amount of 7.25% Debentures due 2014 issued and an aggregate of $333,000 principal amount of convertible debentures converted to trust units.

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 $2.5 million for the three months ended March 31, 2007. This $1.1 million increase over the $1.4 million expensed in 2006 is mainly due to the amortization of the commitment fees on the credit facility negotiated in 2006.

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 slightly as compared to the U.S dollar. As a result we incurred an unrealized gain on our senior notes of $2.7 million. In connection with the purchase of North Atlantic, we have maintained approximately US$650 million of bank debt which contributed a further $7.1 million to the unrealized foreign exchange gains for the three month period ended March 31, 2007. In addition, we also incurred $0.8 million of unrealized foreign exchange gains on transactions incurred by North Atlantic and realized gains of $0.1 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

On October 31, 2006, the Government of Canada announced plans to introduce a tax on publicly traded income trusts. For existing income trusts, the new tax measures would be effective for 2011, provided we comply with the "normal growth" parameters regarding equity growth until that time. A "Notice of Ways and Means Motion" was passed in Parliament shortly after the government announcement. This notice was a summary of the government’s proposal and did not specify the particular amendments to the Income Tax Act.

On December 15, 2006, the government announced safe harbour guidance regarding "normal growth." The safe harbour amount will be measured by reference to the trust’s market capitalization as of the end of trading on October 31, 2006 (which was approximately $3.7 billion for Harvest). For the period from November 1, 2006 to December 31, 2007 a trust’s safe harbour amount will be 40% of the October 31, 2006 market capitalization benchmark and for each of the years 2008 through to and including 2010 will be 20% of the benchmark. In addition, we understand that trusts will be able to issue equity to retire debt existing on October 31, 2006 without eroding their safe harbour limits.

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Should the tax legislation become substantively enacted, future income taxes may be adjusted to include temporary differences between the accounting and tax bases of the Trust’s assets and liabilities. In addition, reserves reported under National Instrument 51-101 may be adjusted to include an estimate of the tax effect on our estimated future revenues from our reserves. We will assess alternative organizational structures during the four-year transition period, however, we are confident that regardless of the final tax legislation or our structure we will continue to provide value to our unitholders. As of March 31, 2007, this proposed tax legislation has not been substantively enacted and accordingly, no such adjustments have been made to our interim consolidated financial statements for the three months ended March 31, 2007.

During 2006, we have integrated Viking and Birchill into the Harvest organization in such a fashion that much of the value of these acquisitions is attributed to the net profits interests on the respective petroleum and natural gas properties created subsequent to their acquisition. The value of the net profits interest resides within the Trust while the tax basis associated with these acquisitions is retained by our corporate entities. The net result of this approach to integration for income tax purposes is that the book basis and the tax basis of our petroleum and natural gas assets held in corporate entities are approximately equal resulting in no recorded future income taxes beyond the recovery of $2.3 million in the prior year.

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	1,651,872	-	65,000	1,586,872	-
Interest on long-term debt(4)	257,202	74,907	141,628	40,667	-
Interest on convertible debentures(3)	368,497	45,672	116,329	113,197	93,299
Operating and premise leases	18,117	4,715	10,729	2,415	258
Capital commitments(5)	14,165	11,285	2,880	-	-
Asset retirement obligations(6)	698,475	10,628	13,058	13,321	661,468
Transportation (7)	4,099	1,498	2,345	256	-
Purchase commitments	9,327	9,327	-	-	-
Pension contributions	27,882	585	3,345	4,805	19,147
Feedstock commitments	798,497	791,720	6,777	-	-
Total	3,848,133	950,337	362,091	1,761,533	774,172

(1)    As at March 31, 2007, we had entered into physical and financial contracts for production with average deliveries of approximately 26,655 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 15 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.

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 three month period ended March 31, 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 month period ended March 31, 2007 with the most significant difference being that the deferred charges previously presented as an asset are now netted against the respective debt giving rise to the charges. 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 month period ended March 31, 2007.

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LIQUIDITY AND CAPITAL RESOURCES

At the end of March 2007, we had total debt and equity of $5,730.9 million, an increase of $174.7 million compared to $5,556.2 million at the end of December 2006. During the first quarter 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 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, and

The issuance of 1,802,681 trust units pursuant to Harvest’s Premium Distribution^TM, Distribution Reinvestment and Optional trust unit Purchase Plan (the "DRIP Plans") raising $43.8 million.

	March 31,	December 31,
(in millions)	2007	2006
DEBT
Credit Facilities
- Three Year Extendible Revolving Credit Facility	$1,363.2	$1,306.0
- Senior Secured Bridge Facility	-	289.7
Total Bank Debt	1,363.2	1,595.7
77/8 % Senior Notes Due 2011 (US$250 million) (1)	288.7	291.4
Convertible Debentures, at principal amount
10.5% Debentures Due 2008	26.6	26.6
9% Debentures Due 2009	1.1	1.2
8% Debentures Due 2009	2.1	2.2
6.5% Debentures Due 2010	37.9	37.9
6.4% Debentures Due 2012	174.7	174.8
7.25% Debentures Due 2013	379.5	379.5
7.25% Debentures Due 2014	230.0	-
Total Convertible Debentures	851.9	622.2
Total Debt	2,503.8	2,509.3
TRUST UNITS
130,072,293 issued at March 31, 2007	3,227.1
122,096,172 issued at December 31, 2006		3,046.9
TOTAL DEBT AND TRUST UNITS	$5,730.9	$5,556.2
(1) Face value converted at the period end exchange rate.

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During the three month period ended March 31, 2007, our Cash Flow totaled $213.9 million and we declared distributions to our Unitholders aggregating to $145.3 million ($43.8 million of which was reinvested through our distribution reinvestmentplans) resulting in $112.4 million retained for our capital programs. During the first quarter of 2007, our capital spending aggregated to $153.4 million with $112.4 million funded from Cash Flow and the residual funded with our credit lines. This compares with Cash Flow of $101.0 million ($95.9 million after including $5.1 million of one time cash transaction costs relating to the acquisition of Viking) and distributions declared of $94.8 million, net of $29.9 million reinvested through our distribution reinvestment plans in the prior year.

Management, together with the Board of Directors of Harvest, continually assess distributions relative to cash flow projections, debt leverage and capital spending plans. On April 11, 2007 we announced the declaration of a $0.38 per trust unit distribution for each of April, May and June 2007 based on forecasted commodity price levels and operating performance that are consistent with the current environment. Of the distributions declared for the first three months of 2007 totaling $145.3 million and representing 68% of Cash Flow, $43.8 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 with the residual $67.7 million of proceeds applied to the $1.4 billion Three Year Extendible Revolving Facility thereby increasing our undrawn credit capacity.

As anticipated, 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. Accordingly, our Three Year Extendible Revolving Credit Facility now consists of $1,535 million maturing April 2010 and $65 million 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 March 31, 2007, our Bank Debt to annualized first quarter Cash Flow ratio was 1.6 to 1.0, Total Debt (excluding convertible debentures) to annualized first quarter Cash Flow was 1.9 to 1.0 while the Bank Debt to Total Capitalization was 24% and Total Debt to Total Capitalization was 44%.

Concurrent with the closing of the North Atlantic acquisition, North Atlantic entered into a Supply and Offtake Agreement with Vitol Refining S.A., a third party related to the vendor of North Atlantic, that during the term of 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 Refining S.A. and that Vitol Refining S.A. 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,

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• 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 Refining S.A., 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 Refining S.A. 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 March 31, 2007, we estimate that the outstanding commitments under the Supply and Offtake Agreement aggregated to approximately $798.5 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
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

Following the October 31, 2006 announcement, the trading value of our trust units sustained a significant drop in trading range and only now is returning to within 10% of its 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.

Disclosure of Outstanding Trust Unit Data

We are authorized to issue an unlimited number of trust units. As at May 8, 2007, we had 130,634,164 trust units outstanding, 3,741,375 of Unit Appreciation Rights outstanding (of which 576,100 are exercisable) and 308,475 awards issued under the Unit Awards Incentive Plan (of which 106,848 were exercisable). In addition, we had seven series of convertible debentures outstanding that are convertible into 26,367,959 trust units.

Distributions to Unitholders and Taxability

In the three month period ended March 31, 2007, we declared monthly distributions of $0.38 per trust unit ($145.3 million) to Unitholders, 68% of our Cash Flow, and have declared a monthly distribution of $0.38 per trust unit for the second quarter of 2007 as well. The $50.5 million increase in distributions declared during the first three months of 2007 as compared to $94.8 million in the prior year is primarily due to an increase of 29,525,764 trust units outstanding following the acquisitions of Viking, Birchill and North Atlantic in 2006 (limited to an additional one month with respect to the Viking acquisition) along with issuance under our distribution re-investment plans.

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Three Month Period ended March 31

	Three Month Period ended March 31
(000s except per trust unit amounts)		2007		2006	Change
Distributions declared	$	145,270	$	94,812	53%
Per trust unit	$	1.14	$	1.11	3%
Taxability of distributions		100%		100%	-
Payout ratio(1)		68%		94%	(26%)
(1)Cash flow 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 no have taxable income.

OUTLOOK

During the first quarter of 2007, we benefited from robust refining margins and a significant narrowing of differentials between the WTI benchmark price and light to medium oil and heavy oil prices in western Canada. While we do not attempt to forecast commodity prices nor forecast Cash Flow or the level of cash distributions, strong refining margins and the narrowing of product quality differentials have continued into the second quarter.

In assessing our guidance for the balance of 2007, we continue to anticipate daily production to average 66,000 boe/d for the balance of 2007 but are adjusting our operating cost expectations to a range $11.00 to $11.50 per boe for our petroleum and natural gas operations with our annual capital expenditures unchanged at $295 million. For our refining and marketing business, we are maintaining our annual throughput expectations of 111,400 bbls/d of feedstock (excluding purchased fuel oil consumed by the plant) and are shifting our unit operating cost estimate to the higher end of our $4.40 to $4.60 range with capital spending unchanged at $60 million with approximately $30 million invested in maintenance capital and discretionary capital spending ranging from $15 million to $30 million for a visbreaker unit upgrade as well as other discretionary projects. With our Cash Flow in 2007 expected to increase with the Refinery acquisition and increases in the floor prices of our oil price risk management contracts and assuming a $0.38 per trust unit monthly distribution level, we anticipate a reduction in our 2007 payout ratio.

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 on prices above US$55.67 for 26,655 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 25% of our crude oil production. This significantly reduces the volatility of our cash flows to WTI prices if 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 balance of 2007, we have entered into natural gas price contracts that provide the following three way price structure on 30,000 GJ/d for the period from April 2007 through March 2008:

For market prices below $5, a price equal to the market price plus $2;
For market prices between $5 and $7, a fixed price of $7;
For market prices between $7 and $10.27, market prices; and,
For market prices higher than $10.27, a price of $10.27.

After considering an 18% average royalty rate, these contracts reduce our AECO natural gas price exposure at prices less than $7 to 55% of our expected natural gas production. We may add a further 20,000 GJ/d of natural gas price protection. 25

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We have also entered into contracts to fix the price of 35 megawatthours (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 these 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.

In assessing our future cash flow risk management (including the impact of our acquisition of North Atlantic), we have concluded that the contracting for price protection on refined products, rather than the crude oil price, will most likely better serve our efforts to add stability to our future cash flows. Accordingly, we will commence contracting for refined product price protection and will also continue to contract for protection on AECO natural gas prices as well as fix the currency exchange rate for US dollars to Canadian dollars along with a measured approach to negotiating fixed prices for electricity. Our objective of these cash flow risk management initiatives is to add stability to our future cash flows to fund long term sustainable cash distributions in a wide variety of pricing environments.

Our growth strategies for the petroleum and natural gas operations in western Canada will be to continue to acquire properties adjacent to our existing operations on favourable terms as well as develop our extensive resource position with capital spending of $295 million planned for 2007. In addition, we intend to be an active participant in the consolidation of Canadian energy royalty trusts which is dependent on the currency value of our trust units as trust-on-trust mergers are expected to be negotiated based on market valuations.

Following the announcement on October 31, 2006 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, we continue to monitor related developments but continue to wait for firm guidelines and the details of the proposed legislation. As of March 31, 2007, we estimate that 58% of our Unitholders are non-Canadian residents, an increase of 4% since December 31, 2006 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 the most efficient capital structure for our Unitholders balancing the benefits of the remaining four years of tax efficient distributions 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 expected Cash Flow for the last nine months of 2007 to changes in the following key factors to our business:

		Assumption		Change	Impact on Cash Flow
WTI oil price (US$/bbl)	$	60.00	$	5.00	$	0.57 / Unit
CAD/USD exchange rate	$	0.90	$	0.02	$	0.14 / Unit
AECO daily natural gas price	$	7.00	$	1.00	$	0.20 / Unit
Refinery crack spread (US$/bbl)	$	9.30	$	1.00	$	0.27 / Unit
Operating Expenses (per boe)	$	11.25	$	1.00	$	0.14 / Unit

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SUMMARY OF QUARTERLY RESULTS

The table and discussion below highlight our first quarter 2007 performance over the preceding seven quarters on selectmeasures.

	2007		2006								2005
(000s except where noted)		Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2
Revenue, net of royalties	$	1,025,512	$	682,744	$	259,818	$	257,103	$	181,160	$	154,646	$	169,654	$	120,263
Net income (loss)	$	69,850	$	1,533	$	107,768	$	60,682	$	(33,937)	$	75,638	$	52,862	$	19,516
Per trust unit, basic2	$	0.55	$	0.01	$	1.01	$	0.60	$	(0.41)	$	1.45	$	1.09	$	0.45
Per trust unit, diluted2	$	0.55	$	0.01	$	0.99	$	0.60	$	(0.41)	$	1.42	$	1.08	$	0.44
Cash Flow1	$	213,941	$	156,270	$	147,471	$	147,010	$	100,971	$	96,431	$	103,508	$	57,217
Per trust unit, basic1	$	1.68	$	1.35	$	1.39	$	1.45	$	1.23	$	1.84	$	2.14	$	1.32
Per trust unit, diluted1	$	1.52	$	1.29	$	1.34	$	1.43	$	1.22	$	1.81	$	2.09	$	1.29
Distributions per Unit, declared	$	1.14	$	1.14	$	1.14	$	1.14	$	1.11	$	1.05	$	0.95	$	0.60
Total long term financial liabilities	$	2,436,018	$	2,478,518	$	1,105,728	$	746,840	$	735,896	$	349,074	$	386,124	$	455,163
Total assets	$	5,800,346	$	5,745,558	$	4,076,771	$	3,455,918	$	3,470,653	$	1,308,481	$	1,327,272	$	1,117,792
(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. In the third quarter of 2005, net revenues increased due to the higher production from our Hay River acquisition in August 2005, stronger crude oil prices and narrower heavy oil differentials which did not continue into the fourth quarter of 2005. The growth in cash flows is closely aligned with the growth in net revenues and is attributed to the same factors as is the growth in net revenues.

Net income reflects both cash and non-cash items. Changes in non-cash items, including 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. 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 Cash Flow.

Growth in total assets over the last eight quarters is directly attributed to our acquisition of the Hay River assets in the third quarter of 2005, 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 Cash Flows 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;

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•      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 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.

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Employee Future Benefits

We maintain a defined benefit pension plan related to 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 ratified a strategic plan that will result in Canadian GAAP, as used by public companies, being converged with International Financial Reporting Standards over a transitional period. The Accounting Standards Board ("AcSB") is expected to develop and publish a detailed implementation plan with a transition period expected to be approximately five years. 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.

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Accounting changes

The AcSB issued CICA Section 1506, Accounting Changes. The standard prescribes the criteria for changing accounting policies, together with the accounting treatment and disclosure of changes in accounting policies and estimates, and correction of errors. The standard requires the retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impractical to determine either the period-specific effects or the cumulative effect of the change. Application is on a prospective basis and is effective for changes in accounting policies and estimates and correction of errors made in fiscal years beginning on or after January 1, 2007.

Variable Interest Entities

The Emerging Issues Committee (EIC) issued EIC Abstract 163 – Determining the Variability to be Considered in Applying AcG 15. This Abstract, which is harmonized with the equivalent United States FASB Staff Position (FSP) FIN 46(R) – 6 – Determining the Variability to be Considered in Applying FASB Interpretation No. 46(R), provides guidance on how an enterprise should determine the variability to be considered in applying AcG 15 – Consolidation of Variable Interest Entities. The Abstract is to be applied prospectively to all entities with which an enterprise first becomes involved and to all entities previously required to be analyzed under AcG 15 when a reconsideration event has occurred beginning the first day of the first reporting period beginning on or after January 1, 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

Remunerating employees with a combination of average industry salary and benefits combined with a merit based bonus plan to reward success in execution of our business plan.

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.

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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.

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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 Cash Flow as cash flow from operating activities before changes in non-cash working capital, settlement of asset retirement obligations and one time transaction costs. Cash Flow as presented is not intended to represent an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with Canadian GAAP. Management uses Cash Flow to analyze operating performance and leverage. Payout Ratio, Cash G&A and Operating Netbacks are additional non-GAAP measures used extensively in the Canadian energy trust sector for comparative purposes. Payout Ratio is the ratio of distributions to total Cash Flow. Operating Netbacks are always reported on a per boe basis, and include gross revenue, royalties and operating expenses, net of any realized gains and losses on related risk 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. Operating income and operating cash flow are also commonly used in the petroleum and natural gas and refining industries to reflect operating results and cash flows before items not directly related to operations.

For the three months ended March 31, 2007 and 2006, Cash Flows are reconciled to its closest GAAP measure, Cash Flow from operating activities, as follows:

	Three months ended March 31
(000s)		2007		2006
Cash Flow	$	213,941	$	100,971
Cash Viking transaction costs		-		(5,072)
Settlement of asset retirement obligations		(2,120)		(1,118)
Changes in non-cash working capital		(100,773)		(6,617)
Cash flow from operating activities	$	111,048	$	88,164

Forward-Looking Information

This MD&A highlights significant business results and statistics from our consolidated financial statements for the three months ended March 31, 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, Cash Flow From Operations and regulatory changes. For this purpose, any statements that are contained herein that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements often contain terms such as "may", "will", "should", "anticipate", "expects", and similar expressions.

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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.

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