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, 2009 and 2008, our MD&A for the year ended December 31, 2009 as well as our interim consolidated financial statements and notes for the three month period ended March 31, 2010 and 2009.  The information and opinions concerning our future outlook are based on information available at May 10, 2010.

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 (“mcf”) of natural gas to one barrel of oil (“bbl”).  Boes may be misleading, particularly if used in isolation.  A boe conversion ratio of 6 mcf to 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, petroleum and natural gas revenues are reported on a gross basis before deduction of Crown and other royalties.  In addition to disclosing reserves under the requirements of National Instrument 51-101, we also disclose our reserves on a company interest basis which is not a term defined under National Instrument 51-101.  This information may not be comparable to similar measures by other issuers.

NON-GAAP MEASURES

Throughout this MD&A we have referred to certain measures of financial performance that are not specifically defined under Canadian GAAP.  Cash G&A and Operating Netbacks are non-GAAP measures used extensively in the Canadian energy trust sector for comparative purposes.  Cash G&A are G&A expenses excluding the effect of our unit based compensation plans, while Operating Netbacks are always reported on a per boe basis, and include gross revenue, royalties, operating expenses, and transportation and marketing expenses.  Gross Margin is also a non-GAAP measure and is commonly used in the refining industry to reflect the net funds received from the sale of refined products after considering the cost to purchase the feedstock and is calculated by deducting purchased products for resale and processing from total revenue.  Earnings From Operations is also a non-GAAP measure commonly used in the petroleum and natural gas and refining industries to reflect operating results before items not directly related to operations.

FORWARD-LOOKING INFORMATION

This MD&A highlights significant business results and statistics from our consolidated financial statements for the three months ended March 31, 2010 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 refining and marketing 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, the forward looking statements made in the “Outlook” section as well as statements made throughout with reference to production volumes, refinery throughput volumes, royalty rates, operating costs, commodity prices, administrative costs, price risk management activity, acquisitions and dispositions, capital spending, reserve estimates, distributions, access to credit facilities, income taxes, cash from operating activities, 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, estimates or opinions change, except as required by law.  Forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

Review of Overall Performance

· Cash flow from operating activities decreased $141.6 million to $80.2 million in the First Quarter of 2010 compared to $221.7 in the First Quarter of 2009.  This decrease is primarily due to a decrease in contribution from our Downstream operations of $176.0 million, coupled with a decrease in realized gains on settlement of commodity price risk management contracts of $26.6 million and a decrease of $24.8 million in non-cash working capital; these decreases were partially offset by an increase in contribution from our Upstream operations of $81.5 million.

· Upstream operations contributed $152.9 million of cash for the First Quarter of 2010 compared with prior year of $71.3 million; this increase is predominantly due to stronger commodity prices as the average West Texas Intermediate benchmark price for the First Quarter 2010 increased 83% over the same period in the 2009, somewhat offset by a 3,937 boe/d decrease in production to 50,178 boe/d for the First Quarter of 2010.  In addition, our operating costs decreased by $1.24/boe to $14.23/boe in the First Quarter 2010 compared to the same quarter of 2009 which is primarily attributed to lower electrical power costs.

· Upstream capital spending of $115.4 million includes the drilling of 80 (net 65.9) wells with a success ratio of 100%.

· Downstream operations had a negative cash contribution of $34.0 million during the First Quarter of 2010 and refining gross margin averaged US$0.54/bbl reflecting a US$14.64/bbl decrease over the prior year mainly due the shutdown of production units for approximately eight weeks to conduct repairs in the gasoline section of the refinery as a consequence of a fire in early January 2010.  Total repair costs associated with the fire were approximately $5.4 million. During the First Quarter of 2010, refining operating costs averaged $6.81/bbl of throughput as compared to $2.05/bbl in the prior year and the cost of purchased energy averaged $4.18/bbl of throughput in the First Quarter of 2010 as compared to $1.77/bbl in the prior year.  The increase in the cost per barrel for both operating costs and purchased energy reflects decreased throughput for the three months ended March 31, 2010 combined with increased pricing for the purchased energy.

· Downstream capital expenditures totaled $8.7 million during the quarter including $5.9 million related to debottlenecking projects.

· KNOC’s acquisition of Harvest’s Trust Units triggered the “change of control” provisions included within the convertible debentures and the 77/8% Senior Notes indentures which required Harvest to make an offer to purchase 100% of the outstanding Convertible Debentures and 77/8% Senior Notes for cash consideration of 101% of the principal amount thereof plus accrued and unpaid interest. As a result, $156.4 million principal amount of convertible debenture were redeemed and US$40.4 million principal amount of 77/8% Senior Notes were redeemed.

· Harvest issued 46,567,852 Trust Units to KNOC Canada Ltd. for total proceeds of $465.7 million which were used to pay down the credit facility and to establish funding for potential convertible debenture and 7 7/8% Senior Note redemptions under the “change of control” provisions.

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SELECTED INFORMATION

The table below provides a summary of our financial and operating results for the three months ended March 31, 2010 and 2009.

	Three Months Ended March 31
(in $000’s except where noted)	2010			2009			Change
Revenue, net(1)		569,762			731,095			(22	)%
Cash From Operating Activities		80,160			221,745			(64	)%
Per Trust Unit, basic	$	0.29		$	1.40			(79	)%
Per Trust Unit, diluted	$	0.29		$	1.28			(77	)%
Net Income (Loss)(2)		(48,795	)		56,864			(186	)%
Per Trust Unit, basic	$	(0.18	)	$	0.36			(150	)%
Per Trust Unit, diluted	$	(0.18	)	$	0.36			(150	)%
Distributions declared		-			103,302			(100	)%
Distributions declared, per Trust Unit	$	-		$	0.65			(100	)%
Distributions declared as a percentage of Cash From Operating Activities		-			47	%		(100	)%
Bank debt		187,884			1,233,843			(85	)%
77/8% Senior Notes		210,314			309,325			(32	)%
Convertible Debentures(3)		691,939			830,757			(17	)%
Total long-term financial debt(3)		1,090,137			2,373,925			(54	)%
Total assets		4,402,329			5,785,269			(24	)%
UPSTREAM OPERATIONS
Total daily sales volumes (boe/d)		50,178			54,115			(7	)%
Operating Netback ($/boe)	$	36.20		$	16.45			120	%
Capital expenditures		115,401			108,710			6	%
Business and property acquisitions, net		30,961			675			4487	%
Abandonment and reclamation expenditures		5,650			3,466			63	%
DOWNSTREAM OPERATIONS
Average daily throughput (bbl/d)		41,016			104,296			(61	)%
Average Refining Margin (US$/bbl)	$	0.54		$	15.18			(96	)%
Capital expenditures		8,683			6,904			26	%

(1) Revenues are net of royalties.

(2) Net Income (Loss) includes a future income tax recovery of $5.0 million (2009 – expense of $2.0 million) and an unrealized net gain from risk management activities of $0.1 million (2009 - net losses of $10.2 million) for the three months ended March 31, 2010.

(3) Includes current portion of Convertible Debentures.

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Business Segments

The following table presents selected financial information for our two business segments:

	Three Months Ended March 31
	2010						2009
(in $000’s)	Upstream		Downstream		Total		Upstream		Downstream		Total
Revenue(1)		229,975		339,787		569,762		158,391		572,704		731,095
Capital expenditures		115,401		8,683		124,084		108,710		6,904		115,614
Total assets(2)		3,112,105		1,290,224		4,402,329		3,928,531		1,831,039		5,785,269

(1) Revenues are net of royalties.

 (2) Total assets on a consolidated basis as at March 31, 2010 includes nil relating to the fair value of risk management contracts (2009 - $25.7 million).

Our upstream and downstream operations are each discussed separately in the sections that follow.  Additionally, we have included a section entitled “Risk Management, Financing and Other” that discusses, among other things, our cash flow risk management program.

UPSTREAM OPERATIONS

Summary of Financial and Operating Results

	Three Months Ended March 31
(in $000’s except where noted)	2010			2009			Change
Revenues		271,731			182,920			49	%
Royalties		(41,756	)		(24,529	)		(70	)%
Net revenues		229,975			158,391			45	%
Operating expenses		64,253			75,335			(15	)%
General and administrative		10,600			7,394			43	%
Transportation and marketing		2,207			2,932			(25	)%
Depreciation, depletion, amortization and accretion		107,595			117,012			(8	)%
Earnings From Operations(1)		45,320			(44,282	)		202	%
Cash capital expenditures (excluding acquisitions)		115,401			108,710			6	%
Property and business acquisitions, net of dispositions		30,961			675			4487	%
Abandonment and reclamation expenditures		5,650			3,466			63	%
Daily sales volumes
Light to medium oil (bbl/d)		24,487			24,233			1	%
Heavy oil (bbl/d)		9,250			11,141			(17	)%
Natural gas liquids (bbl/d)		2,816			2,837			(1	)%
Natural gas (mcf/d)		81,752			95,421			(14	)%
Total (boe/d)		50,178			54,115			(7	)%

(1) This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.

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Commodity Price Environment

	Three Months Ended March 31
Benchmarks	2010		2009		Change
West Texas Intermediate crude oil (US$ per barrel)		78.71		43.08		83	%
Edmonton light crude oil ($ per barrel)		80.27		49.59		62	%
Bow River blend crude oil ($ per barrel)		73.55		44.09		67	%
AECO natural gas daily ($ per mcf)		4.95		4.92		1	%
Canadian / U.S. dollar exchange rate		0.961		0.804		20	%

The average WTI benchmark price in the First Quarter 2010 was 83% higher than the First Quarter 2009 average price, as the commodity prices recovered from the global economic down turn in prior periods.  The average Edmonton light crude oil price (“Edmonton Par”) and Bow River blend crude oil price (“Bow River”) also experienced significant increases over the First Quarter of the prior year due to recovering commodity prices.

The average First Quarter 2010 AECO daily natural gas price was 1% higher than the First Quarter of 2009 due to slight decreases in storage levels and increases in economic activity which has led to a small increase in industrial consumption.

	2010			2009												2008
Differential Benchmarks	Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2
Bow River Blend differential to Edmonton Par ($/bbl)		6.72			7.81			6.62			3.91			5.50			14.07			16.48			21.50
Bow River Blend differential as a % of Edmonton Par		8.4	%		10.2	%		9.2	%		5.9	%		11.1	%		22.2	%		13.5	%		17.1	%

Heavy oil differentials fluctuate based on a combination of factors including the level of heavy oil inventories, pipeline capacity to deliver heavy crude to U.S. markets and the seasonal demand for heavy oil.  In the First Quarter of 2010, Bow River heavy oil differential relative to Edmonton Par tightened to an average of $6.72/bbl (8.4%) compared to $5.50/bbl (11.1%) in the prior year.

Realized Commodity Prices(1)

The following table summarizes our average realized price by product for the three months ended March 31, 2010 and 2009.

	Three Months Ended March 31
	2010		2009		Change
Light to medium oil ($/bbl)		74.35		40.99		81	%
Heavy oil ($/bbl)		65.98		37.16		78	%
Natural gas liquids ($/bbl)		59.89		41.22		45	%
Natural gas ($/mcf)		5.13		5.33		(4	)%
Average realized price ($/boe)		60.17		37.56		60	%

(1) Realized commodity prices exclude the impact of price risk management activities.

Our realized prices for light to medium oil and heavy oil increased by 81% and 78% respectively in the First Quarter of 2010 as compared to the same period in the prior year, reflecting the recovery in commodity prices.  Our average realized price for our natural gas production decreased marginally in the First Quarter of 2010.

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Sales Volumes

The average daily sales volumes by product were as follows:

	Three Months Ended March 31
	2010					2009
	Volume		Weighting			Volume		Weighting			% Volume Change
Light to medium oil (bbl/d)(1)		24,487		49	%		24,233		45	%		1	%
Heavy oil (bbl/d)		9,250		18	%		11,141		21	%		(17	)%
Natural gas liquids (bbl/d)		2,816		6	%		2,837		5	%		(1	)%
Total liquids (bbl/d)		36,553		73	%		38,211		71	%		(4	)%
Natural gas (mcf/d)		81,752		27	%		95,421		29	%		(14	)%
Total oil equivalent (boe/d)		50,178		100	%		54,115		100	%		(7	)%

(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, notwithstanding that, it benefits from a heavy oil royalty regime and therefore would be classified as heavy oil according to NI 51-101.

During the First Quarter of 2010, our active drilling program resulted in several wells being brought online late in the quarter which partially offset the natural declines.  In the First Quarter of 2010, Harvest’s average daily production of light/medium oil was 24,487 bbl/d compared to prior period of 24,233 bbl/d.  Heavy Oil decreased 1,891 bbl/d due to natural declines and reduced capital spending throughout 2009.  Natural gas liquids remained consistent, producing 2,816 bbl/d compared to prior period of 2,837 bbl/d.  Natural gas production averaged 81,752 mcf/d in the First Quarter of 2010 compared to prior period of 95,421 mcf/d, the decrease is attributable to natural declines and minimal investment in gas properties in 2009.

Revenues

	Three Months Ended March 31
(in $000’s)	2010			2009			Change
Light to medium oil sales	$	163,857		$	89,405			83	%
Heavy oil sales		54,931			37,255			47	%
Natural gas sales		37,765			45,735			(17	)%
Natural gas liquids sales and other		15,178			10,525			44	%
Total sales revenue		271,731			182,920			49	%
Royalties		(41,756	)		(24,529	)		70	%
Net Revenues	$	229,975		$	158,391			45	%

Our revenue is impacted by changes to production volumes, commodity prices and currency exchange rates.  Our total sales revenue for the three months ended March 31, 2010 of $271.7 million is $88.8 million higher than the same period of the prior year which is attributed to higher realized commodity prices, partially offset by lower production and the strengthening of the Canadian dollar against the US dollar.

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.  Throughout the First Quarter of 2010, net royalties as a percentage of gross revenue were 15.4% (2009 – 13.4%) and aggregated to $41.8 million (2009 - $24.5 million).  The increase in our royalty rate quarter over quarter is due to higher royalty rates in a higher commodity price environment.

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Operating Expenses

	Three Months Ended March 31
	2010						2009				Per BOE
(in $000’s except per boe amounts)	Total			Per BOE			Total		Per BOE		Change
Operating expense
Power and fuel	$	13,045		$	2.89		$	18,028	$	3.70		(22	)%
Well Servicing		12,917			2.86			12,629		2.59		10	%
Repairs and maintenance		10,639			2.35			11,820		2.43		(3	)%
Lease rentals and property taxes		8,116			1.80			7,598		1.56		15	%
Processing and other fees		3,915			0.87			5,031		1.03		(16	)%
Labour – internal		6,254			1.38			6,262		1.29		7	%
Labour – contract		4,021			0.89			3,786		0.78		14	%
Chemicals		3,801			0.84			3,876		0.80		5	%
Trucking		2,105			0.47			3,130		0.64		(27	)%
Other		(560	)		(0.12	)		3,175		0.65		(118	)%
Total operating expense	$	64,253		$	14.23		$	75,335	$	15.47		(8	)%
Transportation and marketing expense	$	2,207		$	0.49		$	2,932	$	0.60		(18	)%

First Quarter 2010 operating costs totaled $64.3 million, a decrease $11.1 million as compared to the same period in the prior year.  On a per barrel basis, operating costs have decreased to $14.23/boe in the first three months of 2010 as compared to $15.47/boe during the same period in the prior year.  The 8% decrease is substantially attributed to lower power and fuel costs and partially offset by reduced production volumes.

Power and fuel costs, comprised primarily of electric power costs, represented approximately 20% of our total operating costs during the First Quarter of 2010.  The average Alberta electric power price of $40.89/MWh in the First Quarter of 2010 was 35% lower than the First Quarter 2009 average price of $63.01/MWh.  Harvest electricity usage in Alberta is exposed to market prices and to mitigate our exposure to electric power price fluctuations, we had electric power price risk management contracts in place which resulted in a loss of $1.0 million.

	Three Months Ended March 31
(per boe)	2010		2009		Change
Electric power and fuel costs	$	2.89	$	3.70		(22	)%
Realized loss on electricity risk management contracts		0.22		-		100	%
Net electric power and fuel costs	$	3.11	$	3.70		(16	)%
Alberta Power Pool electricity price (per MWh)	$	40.89	$	63.01		(35	)%

First Quarter 2010 transportation and marketing expense decreased to $2.2 million ($0.49/boe) as compared to $2.9 million ($0.60/boe) in the First Quarter of 2009.  These costs relate primarily to delivery of natural gas to Alberta’s natural gas sales hub, the AECO Storage Hub, and our cost of trucking clean crude oil to pipeline receipt points.  As a result, the total dollar amount of costs fluctuates in relation with our production volumes while the cost per boe typically remains relatively constant.

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Operating Netback

	Three Months Ended March 31
(per boe)	2010			2009			Change
Revenues	$	60.17		$	37.56			60	%
Royalties		(9.25	)		(5.04	)		84	%
Operating expense		(14.23	)		(15.47	)		(8	)%
Transportation and marketing expense		(0.49	)		(0.60	)		(18	)%
Operating netback(1)	$	36.20		$	16.45			120	%

(1) This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.

Harvest’s operating netback represents the net amount realized on a per boe basis after deducting directly related costs.  In the First Quarter of 2010, our operating netback increased by $19.75/boe or 120% over the same period in the prior year.  The increase in our operating netback is primarily attributed to the recovery of commodity prices.

General and Administrative (“G&A”) Expense

	Three Months Ended March 31
(in $000’s except per boe)	2010		2009			Change
Cash G&A	$	10,600	$	8,653			23	%
Unit based compensation (recovery) expense		-		(1,259	)		(100	)%
Total G&A	$	10,600	$	7,394			43	%
Cash G&A per boe	$	2.35	$	1.78			32	%

Due to the acquisition of all the Trust Units by KNOC Canada Ltd, the unit based compensation plans have been terminated and there will no longer be any unit based compensation expense in G&A on a go-forward basis. For the three months ended March 31, 2010, Cash G&A costs increased to $10.6 million from $8.7 million in the First Quarter 2009 resulting in an increase of 23%.  Approximately $1.4 million of this increase is related to the implementation of a Long Term Incentive program to replace our unit based compensation plans; the remaining $0.5 million increase is primarily due to annual salary increases.   Generally, approximately 75% of Cash G&A expenses are related to salaries and other employee related costs.

Depletion, Depreciation, Amortization and Accretion Expense

	Three Months Ended March 31
(in $000’s except per boe)	2010		2009		Change
Depletion, depreciation and amortization	$	96,896	$	106,209		(9	)%
Depletion of capitalized asset retirement costs		4,444		4,748		(6	)%
Accretion on asset retirement obligation		6,256		6,055		3	%
Total depletion, depreciation, amortization and accretion	$	107,595	$	117,012		(8	)%
Per boe	$	23.83	$	24.03		(1	)%

Our overall depletion, depreciation, amortization and accretion (“DDA&A”) expense for the three months ended March 31, 2010 was $9.4 million lower compared to the same period in the prior year.  The decrease is attributed to lower production volumes.

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Capital Expenditures

	Three Months Ended March 31
(in $000’s)	2010		2009			Change
Land and undeveloped lease rentals	$	170	$	834			(80	)%
Geological and geophysical		8,550		1,015			742	%
Drilling and completion		73,761		60,022			23	%
Well equipment, pipelines and facilities		29,505		43,810			(33	)%
Capitalized G&A expenses		3,226		2,762			17	%
Furniture, leaseholds and office equipment		189		267			(29	)%
Development capital expenditures excluding acquisitions and non-cash items		115,401		108,710			6	%
Non-cash capitalized G&A recoveries		-		(302	)		100	%
Total development capital expenditures excluding acquisitions	$	115,401	$	108,408			6	%

The first Quarter of  2010 was very active for Harvest with approximately 74% our capital program focused on drilling activity in our Light/Medium and Heavy Oil Pools. We completed our winter drilling program at Hay River in NE Alberta where we drilled 8 gross (8 net) new wells and completed well tie-in and optimization projects for a total expenditure of  $18.1 million. We continue to see the benefit of our enhanced water injection as production exceeded 7,500 boe/d in the month of March from this medium gravity Bluesky oil pool. At Red Earth, we had one of our most active winter programs in many years with capital expenditures of $36.5 million to drill 16 gross (13.2 net) wells including 11 horizontal wells that have been stimulated using multistage fracturing technology to access light oil in this tight Slave Point reservoir. Harvest is well positioned in this emerging resource play and we are planning for further activity increases for the winter of 2010/2011. We also began application of this technology to our Kindersley Viking Light oil pool where we drilled 6 gross (4.7 net) wells for an expenditure of  $3.2 million, and at Crossfield where we drilled 2 gross (1.9 net) horizontal wells to access tight liquids rich gas in the BQ formation for an expenditure of $6.5 million. At Lloydminster, we continued development of our heavy gravity oil pool with 13 gross (11.5 net) horizontal wells in the Lloydminster formation and drilled 7 gross (6.5 net) wells in various upper Mannville formations on our heavy oil acreage for a total expenditure of $16.8 million. We continued to pursue our inventory of drilling locations at SE Saskatchewan with 7 gross (7 net) wells drilled in the Tilston and Souris valley light oil pools with expenditures of  $7.5 million, and at Suffield where we drilled 5 gross (5.0 net) wells to access incremental heavy oil reserves from the Glauconitic formation for $5.8 million.

In addition to the development activity, we completed the acquisition of producing assets in the Redwater area of Alberta for an expenditure of approximately $28 million. The assets produce approximately 750 boe/d (55% light oil) and Harvest has identified a number of drilling and optimization opportunities.

In the First Quarter, Harvest had a 100% success rate for all wells drilled. The following summarizes Harvest’s participation in gross and net wells drilled during the first three months of 2010:

	Total Wells
Area	Gross		Net
Hay River		8.0		8.0
SE Alberta		6.0		3.1
Rimbey/Markerville		7.0		3.3
SE Saskatchewan		7.0		7.0
Red Earth		16.0		13.2
Suffield		5.0		5.0
Lloydminster Heavy Oil		20.0		18.0
Crossfield		2.0		1.9
Kindersley		6.0		4.7
Other Areas		3.0		1.7
Total		80.0		65.9

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Asset Retirement Obligation (“ARO”)

In connection with property acquisitions and development expenditures, we record the fair value of the ARO as a liability in the same year the expenditures occur.  The associated asset retirement 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 changes in the estimated future cash flows of the underlying obligation.  Our asset retirement obligation increased by $3.4 million during the first three months of 2010 as a result of accretion expense of $6.3 million, new liabilities recorded of $2.8 million, offset by $5.7 million of asset retirement expenditures.

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DOWNSTREAM OPERATIONS

Summary of Financial and Operational Results

	Three Months Ended March 31
(in $000’s except where noted below)	2010			2009		Change
Revenues		339,787			572,704		(41	)%
Purchased feedstock for processing and products purchased for resale		327,208			381,837		(14	)%
Gross margin(1)		12,579			190,867		(93	)%
Costs and expenses
Operating expense		29,752			23,965		24	%
Purchased energy expense		15,430			16,607		(7	)%
Turnaround and catalyst expense		-			4,202		(100	)%
Marketing expense		951			2,979		(68	)%
General and administrative expense		441			355		24	%
Depreciation and amortization expense		18,247			22,184		(18	)%
Earnings (Loss) From Operations(1)		(52,242	)		120,575		(143	)%
Cash capital expenditures		8,683			6,904		26	%
Feedstock volume (bbl/day)(2)		41,016			104,296		(61	)%
Yield ($000’s barrels)
Gasoline and related products		884			3,321		(73	)%
Ultra low sulphur diesel and jet fuel		1,081			3,494		(69	)%
High sulphur fuel oil		1,250			2,370		(47	)%
Total		3,215			9,185		(65	)%
Average refining gross margin (US$/bbl)(3)		0.54			15.18		(96	)%

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

(2) Barrels per day are calculated using total barrels of crude oil feedstock and vacuum gas oil.

(3) Average refining gross margin is calculated based on per barrel of feedstock throughput.

Refining Benchmark Prices

The following average benchmark prices and currency exchange rates are the reference points from which we discuss our refinery’s financial performance:

	Three Months Ended March 31
	2010			2009			Change
WTI crude oil  (US$/bbl)		78.71			43.08			83	%
Brent crude oil (US$/bbl)		77.28			45.67			69	%
Basrah Official Sales Price Discount (US$/bbl)		(3.27	)		(3.75	)		(13	)%
RBOB gasoline (US$/bbl/gallon)		88.18/2.10			52.13/1.24			69	%
Heating Oil (US$/bbl/gallon)		86.00/2.05			56.46/1.34			52	%
High Sulphur Fuel Oil  (US$/bbl)		70.74			36.99			91	%
Canadian / U.S. dollar exchange rate		0.961			0.804			20	%

Benchmark pricing in the First Quarter of 2010 was significantly higher than pricing in the First Quarter of 2009 reflecting changes in market supply and demand.  During the First Quarter of 2010, the Heating Oil crack spread averaged US$7.29/bbl, a decrease of US$6.09/bbl from the US$13.38/bbl averaged in the prior year.  The RBOB Gasoline crack spread averaged US$9.47/bbl in the First Quarter of 2010, an increase of US$0.42/bbl over the US$9.05/bbl averaged in the prior year.  The HSFO price averaged US$7.97/bbl less than WTI in the First Quarter of 2010, an increased discount of US$1.88/bbl over the prior year.

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During the three months ended March 31, 2010, the Canadian/U.S. dollar exchange rate increased 20% over the prior year.  The strengthening of the Canadian dollar in 2010 has decreased the contribution from our Downstream operations as substantially all of its gross margin, cost of purchased energy and expenses associated with the Supply and Offtake Agreement are denominated in U.S. dollars.  The net impact of a stronger Canadian dollar decreased our refining gross margin by $0.4 million in the First Quarter of 2010 as compared to a $34.2 million increase in the prior year.

Summary of Gross Margin

The following table summarizes our Downstream gross margin for the three months ended March 31, 2010 and 2009 segregated between refining activities and petroleum marketing and other related businesses.

	Three Months Ended March 31
	2010						2009
(in $000’s)	Refining		Marketing		Total		Refining		Marketing		Total
Sales revenue(1)		311,040		116,433		339,787		550,214		100,675		572,704
Cost of feedstock for processing and products for resale(1)		308,958		105,936		327,208		372,983		87,039		381,837
Gross margin(2)		2,082		10,497		12,579		177,231		13,636		190,867
Average refining gross margin (US$/bbl)		0.54						15.18

(1)   Downstream sales revenue and cost of products for processing and resale are net of intra-segment sales of $87.7 million for the three months ended March 31, 2010 (2009 - $78.2 million) reflecting the refined products produced by the refinery and sold by the Marketing Division.

(2)   This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.

For the three months ended March 31, 2010, our refining gross margin decreased $175.1 million as compared to the prior year primarily due to the unplanned shutdown of production units as a consequence of a fire in January in the gasoline section of the refinery and due to unfavorable economics.  Marketing operations were also impaired by $3.1 million (23%) in the quarter due to the non-availability of certain products, the negative impact of warmer than normal seasonal temperatures and the higher replacement cost of distillates and conventional gasoline.

Refinery Sales Revenue

Our refinery sales revenue is dependent on the selling price as well as the yield of refined products produced from the crude oil and other feedstocks processed.  Although our yield can be altered slightly by adjusting refinery operations to react to market conditions and seasonal demand, the type of crude oil feedstock processed and refinery performance primarily impacts product yields.  A comparison of our refinery yield, product pricing and revenue for the three months ended March 31, 2010 and 2009 is presented below:

	Three Months Ended March 31
	2010							2009
	Refinery Revenues		Volume			Sales  Price(1)		Refinery Revenues		Volume			Sales  Price(1)
	($000’s of Cdn $)		($$000’s of bbls)			(US$ per bbl/ US$ per US gal)		($000’s of Cdn $)		($$000’s of bbls)			(US$ per bbl/ US$ per US gal)
Gasoline products		85,364		947			86.63/2.06		214,471		3,492			49.38/1.18
Distillates		112,307		1,215			88.83/32.12		224,454		3,273			55.14/1.31
High sulphur fuel oil		113,369		1,530			71.21		111,289		2,473			36.18
		311,040		3,692			80.96		550,214		9,238			47.89
Inventory adjustment				(477	)						(53	)
Total production				3,215							9,185
Yield (as a % of Feedstock) (2)				87	%						98	%

 (1)Average product sales prices are based on the deliveries at our refinery loading facilities.

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

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For the three months ended March 31, 2010, our refinery yield was comprised of 27% gasoline products, 34% distillates and 39% HSFO compared to the First Quarter of the prior year when refinery yield averaged 36%, 38% and 26% for the same products respectively.  The change in product yields is a consequence of an unplanned shutdown of the production units due to a fire in the gasoline section of the refinery in early January of 2010 and the subsequent shutdown of other production units due to unfavorable economics.

The timing of product sales in the First Quarter of 2010 makes it difficult to compare the refinery product sales pricing to the benchmark pricing since most of the refinery product sales consisted of sales for the local market or sales for export in early January prior to the fire and later in March once operations resumed.

In the First Quarter of 2010, our average refined product sales price was US$80.96/bbl (a premium of US$2.25/bbl from WTI) as compared to an average selling price of US$47.89/bbl in the prior year (a premium of US$4.81/bbl over WTI).  This decrease in premium relative to WTI of US$2.56 represents a $9.8 million unfavorable price variance.

During the First Quarter of 2010, the average sales price of our gasoline products of US$86.63/bbl was a US$7.92/bbl premium to the average WTI price as compared to a US$6.30/bbl premium to WTI realized in the prior year, representing a $1.6 million increase in gross margin.  This US$1.62/bbl year-over-year increase in our gasoline refining gross margin relative to WTI is higher than the increase in the RBOB gasoline benchmark crack spread of US$0.42/bbl as a consequence of the fire the timing of sales during the quarter.

During the First Quarter of 2010, the average sales price for our distillate products of US$88.83/bbl was a US$10.12/bbl premium from the average WTI price as compared to a US$12.06/bbl premium over WTI realized in the prior year representing a $2.5 million drop in gross margin.  The US1.94/bbl decrease in our distillate refining gross margin relative to WTI is less than the decrease in the Heating Oil benchmark crack spread of US$6.09/bbl and reflects the limited sales for Downstream operations as a result of the fire and the timing of these sales during the quarter.

During the First Quarter of 2010, the average sales price of our HSFO of US$71.21/bbl was a US$7.50/bbl discount to the average WTI price as compared to an US$6.90/bbl discount in the prior year, representing a $1.0 million decrease in gross margin.  The US$0.60/bbl reduction in our HSFO refining gross margin relative to WTI is less than the increase in the HSFO benchmark discount of US$1.88/bbl as a consequence of the fire and the timing of the sales during the quarter.  In addition, the US$7.50/bbl discount in the First Quarter of 2010 includes the negative impact of product transportation costs in the amount of US$0.94/bbl as compared to a positive impact in the prior year of US$0.36/bbl.

Refinery Feedstock

The volatility of WTI prices from month to month makes it difficult to compare the financial impact of specific crude types when our consumption of crude types varies from month to month and costs are aggregated over the quarter.  Further, our refinery competes for international waterborne crude oil and vacuum gas oil (“VGO”) and the WTI benchmark price reflects a land-locked North American price with limited access to the international markets.

The cost of our feedstock reflects numerous factors beyond WTI prices, including the quality of the crude oil processed, the mix of crude oil types, the costs of transporting the crude oil to our refinery, the operational hedging of the WTI component of our feedstock costs through the Supply and Offtake Agreement, the ten day delay in pricing pursuant to the Supply and Offtake Agreement and for Iraqi crude oil purchased, the Official Selling Price (“OSP”) as set by the Oil Marketing Company of the Republic of Iraq.  The OSP discount is set on a monthly basis and announced for North American deliveries.  Prior to March of 2010, the OSP discount was set relative to WTI, however, in March of 2010, the Oil Marketing Company of the Republic of Iraq changed the OSP basis from WTI to Argus Sour Crude Index (‘ASCI”) which represents the daily value of US Gulf Coast medium sour crude based on physical spot market transactions.

A further complication to the comparison of the financial impact of our feedstock costs year over year in First Quarter of 2010 is the operational impact of the fire on the Isomax and surrounding units in January of 2010.  As a consequence of the fire, the affected units were shutdown for repairs for approximately eight weeks.  As well, remaining production units were shutdown at the end of January as a result of unfavorable economics.

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A comparison of crude oil and VGO feedstock processed for the three months ended March 31, 2010 and 2009 is presented below:

	Three Months Ended March 31
	2010							2009
	Cost of Feedstock			Volume		Cost per Barrel (1)		Cost of Feedstock			Volume		Cost per Barrel(1)
	($000’s of Cdn $)			($$000’s of bbls)		(US$/bbl)		($000’s of Cdn $)			($$000’s of bbls)		(US$/bbl)
Iraqi		179,456			2,249		76.68		292,341			7,023		33.47
Russian		112,583			1,358		79.67		15,139			225		54.10
Venezuelan		4,484			62		69.50		51,521			1,735		23.87
Crude Oil Feedstock		296,523			3,669		77.67		359,001			8,983		32.13
Vacuum Gas Oil		1,861			22		81.29		14,314			403		28.56
		298,384			3,691		77.69		373,315			9,386		31.98
Net inventory adjustment (2)		(6,199	)						(4,817	)
Additives and blendstocks		16,773							7,417
Inventory write-down (recovery) (3)		-							(2,932	)
		308,958							372,983

(1) Cost of feedstock includes all costs of transporting the crude oil to the refinery in Newfoundland.

(2) Inventories are determined using the weighted average cost method.

(3) Inventory write-downs are calculated on a product by product basis using the lower of cost or net realizable value.

As a consequence of the unplanned shutdown in First Quarter of 2010, throughput volume decreased 62% to an average of 39,573 bbl/d as compared to 104,296 bbl/d in the prior year.

As is normal business practice, the WTI component of our feedstock cost is operationally hedged under the Supply and Offtake Agreement with Vitol Refining S.A. (“Vitol”).  When we commit to crude oil purchases, Vitol sells a forward WTI price contract for the next contract month, which results in price fluctuations subsequent to our purchase commitment being offset by the price volatility of the forward price curve.  If the timing between processing the crude oil and the expiration of the forward contract are not aligned, the volume of the forward contract relating to unprocessed crude oil is rolled to the next contract month.  This practice results in better matching of our refined product sales prices with our cost of feedstock.  The persistent contango shape of the NYMEX WTI futures price curve since October 2008 has resulted in operational hedging gains from the rolling forward of these price contracts, which reduce our feedstock costs in the month the feedstock is processed.  During the three months ended March 31, 2010, this operational hedging resulted in reductions to the cost of our feedstock of US$2.8 million as compared to the prior year when this operational hedging resulted in a decrease of US$45.0 million to the cost of our feedstock.  The Supply and Offtake Agreement is more fully described in our Annual Information Form for the year ended December 31, 2009 filed on SEDAR at www.sedar.com.

The cost of our crude oil feedstock averaged US$77.67/bbl during the First Quarter of 2010 representing a US$1.04/bbl discount to WTI as compared to a cost of US$32.13/bbl and a discount of US$10.95/bbl in the prior year.  The US$1.04/bbl discount is comprised of a US$0.95/bbl quality discount (2009 – US$7.30/bbl), plus a US$0.75/bbl operational hedging gain (2009 – US$4.70/bbl), offset by a US$0.66/bbl charge relating to timing under the Supply and Offtake Agreement with Vitol (2009 – US$1.05/bbl).

The average cost of purchased VGO during the First Quarter of 2010 was US$81.29/bbl representing a premium of US$2.58/bbl relative to the WTI price as compared to US$28.56/bbl and an US$14.52/bbl discount in the prior year.  The premium paid in the First Quarter of 2010 is comprised of a US$4.41/bbl pricing premium relative to WTI (2009 – a discount of US$6.64/bbl), a US$2.02/bbl charge relating to timing under the Supply and Offtake Agreement with Vitol (2009 – discount of US$0.95/bbl), offset by a US$3.85/bbl operational hedging gain (2009– US$6.93/bbl).

Included in the additives and blendstocks for the First Quarter of 2010 is the cost of products purchased for resale to the local market.

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Operating Expenses

The following summarizes the operating costs from the refinery and marketing division for the three months ended March 31, 2010 and 2009:

	Three Months Ended March 31
	2010						2009
(in $000’s)	Refining		Marketing		Total		Refining		Marketing		Total
Operating expense		25,137		4,615		29,752		19,214		4,751		23,965
Turnaround and catalyst		-		-		-		4,202		-		4,202
Purchased energy		15,430		-		15,430		16,607		-		16,607
		40,567		4,615		45,182		40,023		4,751		44,774

The largest component of refining operating expense is wages, salaries and benefits that totaled $14.4 million during the First Quarter of 2010 (2009 - $12.3 million) while the other significant components were maintenance and repair costs of $7.1 million (2009 - $2.6 million), insurance of $1.3 million (2009 - $1.6 million) and professional services of $0.8 million (2009 - $0.6 million).  During the three months ended March 31, 2010, refining operating expenses were $6.81/bbl of throughput which is higher than $2.05/bbl in the prior year reflecting the higher maintenance costs related to the fire repairs in the First Quarter of 2010 totaling $5.4 million and the related impact of $1.47/bbl of throughput combined with a reduction in throughput.  During the First Quarter of 2010, the marketing division’s operating expenses of $4.6 million remained relatively unchanged from the $4.8 million incurred in the prior year.

Turnaround and catalyst expenditures for the three months ended March 31, 2009 of $4.2 million relate to costs incurred in preparation of the scheduled turnaround in the Second Quarter of 2009.  There were no similar costs incurred in the First Quarter of 2010.

Purchased energy, consisting of low sulphur fuel oil and electricity, is required to provide heat and power to refinery operations.  In the First Quarter of 2010, the cost of purchased fuel oil decreased $0.3 million due to a $12.7 million decrease in purchased volumes offset by a $12.4 million increase in price; we purchased approximately 176,000 barrels of fuel oil at an average price of US$76.62/bbl as compared to approximately 336,000 barrels purchased in the First Quarter of 2009 at an average price of US$33.91/bbl. Our electricity costs decreased $0.9 million in the First Quarter of 2010 to $1.5 million compared to $2.4 million in the same period in the prior year.  The decreased purchased volumes of low sulphur fuel oil and electricity costs are a consequence of the unplanned shutdown of the units due to the fire previously discussed.  Our purchased energy for the three months ended March 31, 2010 was $4.18/bbl of throughput as compared to $1.77/bbl in the prior year.

Marketing Expense and Other

During the three months ended March 31, 2010, marketing expense was comprised of $0.1 million (three months ended March 31, 2009 - $1.0 million) of marketing fees, based on $0.02/bbl (March 31, 2009 - $0.08/bbl) to acquire feedstock and $1.0 million (three months ended March 31, 2009 - $2.0 million) of “Time Value of Money” charges both pursuant to the terms of the Supply and Offtake Agreement.  The decreased “Time Value of Money” charge is mainly the result of decreased purchased feedstock volume in the First Quarter of 2010 combined with a decrease in the LIBOR rate in 2010 as compared to 2009.  As at March 31, 2010, Harvest had commitments totaling approximately $521.3 million in respect of future crude oil feedstock purchases and related transportation from Vitol.

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Capital Expenditures

Capital spending for the three months ended March 31, 2010 totaled $8.7 million (three months ended March 31, 2009 - $6.9 million) relating to various capital improvement projects including $5.9 million related to debottlenecking projects in the First Quarter.

Depreciation and Amortization Expense

The following summarizes the depreciation and amortization expense for the three months ended March 31, 2010 and 2009:

	Three Months Ended March 31
	2010						2009
(in $000’s)	Refining		Marketing		Total		Refining		Marketing		Total
Tangible assets		15,990		816		16,806		19,546		892		20,438
Intangible assets		1,158		283		1,441		1,384		362		1,746
		17,148		1,099		18,247		20,930		1,254		22,184

The process units are amortized over an average useful life of 20 to 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.

RISK MANAGEMENT, FINANCING AND OTHER

Cash Flow Risk Management

With respect to our cash flow risk management program, see “Cash Flow Risk Management” in our MD&A for the year ended December 31, 2009 filed on SEDAR at www.sedar.com.

During the First Quarter of 2010, Harvest had electricity price swap contracts in place for 25.0 MWh from January to December 2010 at an average price of $59.22 per MWh.  Harvest realized a loss of $1.0 million on these risk management contracts in the First Quarter and the mark-to-market deficiency of $1.9 million was reflected on our balance sheet as at March 31, 2010.  In comparison, during the First Quarter of 2009, Harvest had refined product pricing contracts in place for 12,000 bbl/d of NYMEX heating oil and 8,000 bbl/d of Platts heavy fuel oil; we realized gains on our risk management product contracts totaling $25.5 million due to refined product prices in the First Quarter 2009 being below the floor prices on our contracts.

Interest Expense

	Three Months Ended March 31
(in $000’s)	2010		2009		Change
Interest on short term debt
Bank loan	$	1,370	$	-		100	%
Convertible Debentures		9,565		60		15842	%
77/8%  Senior notes		965		-		100	%
Amortization of deferred finance charges – short term debt		2,302		-		100	%
		14,202		60		23570	%
Interest on long-term debt
Bank loan		-		6,251		(100	)%
Convertible Debentures		17,465		19,113		(9	)%
77/8% Senior Notes		5,120		6,553		(22	)%
Amortization of deferred finance charges – long term debt		-		675		(100	)%
		22,585		32,592		(31	)%
Total interest expense		36,787	$	32,652		13	%

Interest expense, including the amortization of related financing costs, increased $4.1 million (13%) compared to the prior year interest expense.  The increase from prior year is due to the offer to purchase 100% of the outstanding Convertible Debentures for cash consideration of 101% of the principal amount thereof plus accrued and unpaid interest in accordance with the “change of control” provisions included within the Convertible Debenture and the 7 7/8% Senior Note indentures. All redemptions made included accrued and unpaid interest when they were settled.  See the Liquidity and Capital Resources section below for further details related to the redemptions.

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The interest expense on our bank loan was $1.4 million for the First Quarter of 2010, compared to $6.3 million in the prior period.  The decrease is attributed to the significant principal repayment made at the end of 2009 and in the First Quarter of 2010.  During the quarter, interest charges on our bank loan reflected an effective interest rate of 1.09%.  Further details on our credit facility are included under “Liquidity and Capital Resources” and Note 11 to the audited consolidated financial statements for the year ended December 31, 2009 filed on SEDAR at www.sedar.com.

The interest expense on our Convertible Debentures totaled $27.0 million during 2010, representing a $7.9 million increase over the prior year.  The increase in expense is due to the immediate recognition of the unamortized discount related to the principal amount of $156.4 million which was redeemed in the quarter pursuant to the change of control provision in the debenture indentures.  Interest on the Convertible Debentures is based on the effective yield of the debt component of the Convertible Debentures, and as a result, the interest expense recorded is greater than the cash interest paid.  Details on the Convertible Debentures outstanding are fully described in Note 13 to the audited consolidated financial statements for the year ended December 31, 2009 filed on SEDAR at www.sedar.com; details on the redemptions in the current quarter are included under “Liquidity and Capital Resources”.

The interest on our 77/8% Senior Notes totaled $6.1 million for the three months ended March 31, 2010; this is comparable to the $6.6 million incurred in the prior period.  Similar to our Convertible Debentures, interest expense is based on the effective yield, and as a result, the interest expense recorded is greater than the cash interest paid.

Included in short and long term interest expense is the amortization of the discount on the 77/8% 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 facility, all totaling $13.7 million for the period ended March 31, 2010 ($4.2 million for the period ended March 31, 2009).

Currency Exchange

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 77/8% Senior Notes as well as any other U.S. dollar cash balances.  Realized foreign exchange gains of $0.5 million for the three months ended March 31, 2010, have resulted from the settlement of U.S. dollar denominated transactions.  Since December 31, 2009, the Canadian dollar has strengthened resulting in an unrealized foreign exchange loss of $9.7 million for the First Quarter 2010.

Our downstream operations are considered a self-sustaining operation with a U.S. dollar functional currency.  The foreign exchange gains and losses incurred by our downstream operations relate to Canadian dollar transactions converted to U.S. dollars as their functional currency is U.S. dollars.  The cumulative translation adjustment recognized in other comprehensive income represents the translation of our downstream operation’s U.S. dollar functional currency financial statements to Canadian dollars using the current rate method.  During the First Quarter of 2010, the strengthening of the Canadian dollar relative to the U.S. dollar resulted in a $26.9 million net cumulative translation loss (2009 – $49.8 million gain) as the weaker U.S. dollar results in a decrease in the relative value of the net assets in our downstream operations.

Future Income Tax

For the three months ended March 31, 2010, we have recorded a future income tax recovery of $5.0 million resulting in an increase in our net future income tax asset to $69.8 million.  Our future income tax asset will fluctuate during each accounting period to reflect changes in the respective temporary differences between the book value and tax basis of their assets as well as further legislative tax rate changes.  Currently, the principal source of our temporary differences is the difference between the net book value of our corporate entities’ property, plant and equipment versus their unclaimed tax pools.

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Income Tax Reassessment

In January 2009, Canada Revenue Agency issued a Notice of Reassessment to Harvest Energy Trust in respect of its 2002 through 2004 taxation years claiming past taxes, interest and penalties totaling $6.2 million.  The CRA has adjusted Harvest Energy Trust’s taxable income to include their net profits interest royalty income on an accrual basis whereas the tax returns had reported this revenue on a cash basis.  A Notice of Objection has been filed with CRA requesting the adjustments to an accrual basis be reversed.  The Harvest Energy Trust 2005 tax return has also been prepared on a cash basis for royalty income with no taxes payable and, if reassessed by CRA on a similar basis, there would have been approximately $40 million of taxes owing.  The Harvest Energy Trust 2006 tax return has been prepared on an accrual basis including incremental payments required to align the prior year’s cash basis of reporting with no taxes payable.  Management along with our legal advisors believe the CRA has not properly applied the provisions of the Income Tax Act (Canada) that entitle income from a royalty to be included in taxable income on a cash basis and that the dispute will be resolved with no taxes payable by Harvest Energy Trust.  Harvest has filed a Notice of Objection with the CRA and filed a Notice of Appeal with the Tax Court.  The CRA and Harvest have now attended the examinations for discovery in early April 2010.

Contractual Obligations and Commitments

We have contractual obligations and commitments entered into in the normal course of operations including the purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, and land lease obligations.   We also have contractual obligations and commitments that are of a less routine nature as disclosed in the following table:

	Maturity
Annual Contractual Obligations ($000’s)	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Long-term debt(1)	$	1,158,564	$	23,810	$	319,673	$	578,482	$	236,599
Interest on long-term debt(1)		243,991		55,322		122,254		59,123		7,292
Operating and premise leases		32,798		5,137		14,140		12,363		1,158
Purchase commitments(2)		20,240		18,423		1,817		-		-
Asset retirement obligations(3)		1,211,955		6,528		40,214		26,335		1,138,878
Transportation (4)		6,177		3,192		2,780		205		-
Pension contributions(5)		24,964		3,200		8,448		8,789		4,527
Feedstock commitments		521,275		521,275		-		-		-
Total	$	3,219,964	$	636,887	$	509,326	$	685,297	$	1,388,454

(1) Assumes constant foreign exchange rate.

(2) Relates to drilling commitments, AFE commitments and downstream purchase commitments.

(3) Represents the undiscounted obligation by period.

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

(5) Relates to the expected contributions for employee benefit plans.

We have a number of operating leases for 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.

DISTRIBUTIONS TO UNITHOLDERS

Harvest has historically declared monthly distributions to Unitholders based upon expectations of cash from operating activities, capital expenditure plans and debt repayment requirements.  However as KNOC now owns all the issued and outstanding Trust Units, we no longer intend to declare regular monthly distributions.

LIQUIDITY AND CAPITAL RESOURCES

During the First Quarter of 2010, cash flow from operating activities was $80.2 million as compared to $221.7 million in the prior year.  Cash flow from operating activities before changes in non-cash working capital totaled $89.7 million during the First Quarter of 2010 compared to $206.4 million in the First Quarter of 2009. In the First Quarter of 2010, we received a capital injection from KNOC Canada Ltd. totaling $465.7 million which was used to fund the repayment of $240.2 million of bank debt, $42.3 million of senior notes and $156.4 million of convertible debentures. We required an additional $124.1 million for capital expenditures and $31.0 million for net asset acquisitions resulting in a net cash requirement of approximately $38 million.  At the end of the First Quarter of 2010, our bank borrowings totaled $187.9 million with $412.1 million of undrawn credit lines.

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During the First Quarter of 2010, the global economic recovery has continued with an increase in the demand for commodities and higher prices. Similarly, the state of the credit markets has also improved, supporting the renewal of our Revolving Credit Facility.  Standard and Poor’s Ratings Services (“S&P”) and Moody’s Investors Service have recently upgraded their corporate ratings to “BB-” and “Ba2”, respectively, and the 77/8% Senior Notes rating to “BB- and “Ba1”, respectively.  Through a combination of cash from operating activities, available undrawn credit capacity and the working capital provided by the Supply and Offtake Agreement with Vitol, it is anticipated that we will have enough liquidity to fund future operations and forecasted capital expenditures.

The following table summarizes our capital structure as at March 31, 2010 and December 31, 2009 as well as provides the key financial ratios contained in our Revolving Credit Facility.  For a complete description of our Revolving Credit Facility, 77/8% Senior Notes and Convertible Debentures, see Notes 10, 11 and 12, respectively, to our audited consolidated financial statements for the year ended December 31, 2009 filed on SEDAR at www.sedar.com.

(in millions)	March 31,			December 31,
SUMMARY OF CAPITALIZATION	2010			2009
Revolving Credit Facility	$	187.9		$	428.0
77/8% Senior Notes Due 2011 (US$209.6 million)(1)		212.9			262.8
Convertible Debentures, at principal amount		757.8			914.2
Total Debt		1,158.6			1,605.0
Unitholders’ Equity, at book value less equity component of convertible debentures 288,836,653 issued at March 31, 2010		2,757.4
242,268,801 issued at December 31, 2009					2,367.5
TOTAL CAPITALIZATION		3,916.0			3,972.5
FINANCIAL RATIOS
Secured Debt to Annualized EBITDA(2)		0.4			0.7
Total Debt to Annualized EBITDA(2) (3)		2.5			2.7
Secured Debt to Total Capitalization		5	%		11	%
Total Debt to Total Capitalization(3)		30	%		40	%

(1)  Face value converted at the period end exchange rate.

(2)  Annualized Earnings Before Interest, Taxes, Depreciation and Amortization based on twelve month rolling average.

(3) “Total Debt” includes the convertible debentures in 2010 due to the economic elimination of the conversion feature subsequent to the acquisition of Harvest Energy Trust by KNOC.

KNOC’s acquisition of Harvest’s Trust Units triggered the “change of control” provisions included within the Convertible Debentures and the 77/8% Senior Notes indentures, as well as within our $1.6 billion Extendible Revolving Credit Facility. These change of control provisions resulted in the renewal of our credit facility and the redemption of some of our Convertible Debentures and 77/8% Senior Notes.

As a result of this change of control provision, at the end of 2009 an amended Extendible Revolving Credit Facility (“the Facility”) agreement was reached with eight of the original fourteen lenders, maturing April 30, 2010 for a new commitment level of $600 million. On April 30, 2010 the Facility agreement was amended and extended for three years, maturing April 30, 2013 and the capacity was reduced from $600 million to $500 million.  All invited lenders with the exception of one approved the amended and extended Facility, reducing the number of lenders from eight to seven.  We continue to pay a floating interest rate, which is determined by a grid based on our secured debt (excluding 7 7/8% Senior Notes and convertible debentures) to earnings before interest, taxes, depletion, amortizations and other non-cash items (“EBITDA”).  The minimum rate charged in the grid is 200 bps over bankers’ acceptance rates as long as our secured debt to EBITDA ratio remains below or equal to one; we expect to remain below this threshold for the immediate future.  Under the new capacity limit of $500 million, we would have had unutilized borrowing capacity of $312.1 million based on our drawn amount as at March 31, 2010 of $187.9 million.  We have the option to increase the capacity limit from $500 million to $1.0 billion without lender consent; utilizing the accordion feature and securing additional capacity from an existing or new lender.  The financial covenants remain the same as in the past and are listed as:

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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

The “change of control” provision included within the Convertible Debentures’ indentures required Harvest to make an offer to purchase 100% of the outstanding Convertible Debentures for cash consideration of 101% of the principal amount thereof plus accrued and unpaid interest.  Harvest made these offers on January 20, 2010 and by March 4th all of the offers had expired and the following redemptions were made:

· 6.5% Debentures due 2010 – $13.3 million principal amount tendered leaving a principal balance of $23.8 million outstanding

· 6.4% Debenture due 2012 –  $67.8 million principal amount tendered leaving a principal balance of $106.8 million outstanding

· 7.25% Debentures due 2013 – $48.7 million principal amount tendered leaving a principal balance of $330.5 million outstanding

· 7.25% Debentures due 2014 – $13.2 million principal amount tendered leaving a principal balance of $60.1 million outstanding

· 7.5% Debentures due 2015 –  $13.4 million principal amount tendered leaving a principal balance of $236.6 million outstanding

As a result of the KNOC acquisition, the debentures are no longer convertible into Units but investors would receive $10.00 for each unit notionally received based on each series conversion rate.  Because every series of debentures carry a conversion price that exceeds $10.00 per unit, it is assumed that no investor would exercise their conversion option.

Similar to the Convertible Debentures, our 77/8% Senior Notes indenture “change of control” provision required Harvest to make an offer to purchase 100% of the outstanding 77/8% Senior Notes for cash consideration of 101% of the principal amount thereof plus accrued and unpaid interest. On February 16, 2010, the offer expired and US$40,434,000 principal amount was tendered, leaving a principal balance of US$209.6 outstanding.  Harvest may call the remaining 77/8% Senior Notes for redemption at a price of 101.969% of the principal amount plus any accrued and unpaid interest to the redemption date and effective October 15, 2010 and thereafter, at a price of 100% of the principal amount plus any accrued and unpaid interest to the redemption date.

On January 29, 2010 Harvest issued 46,567,852 Trust Units to Korea National Oil Corporation at $10.00 per Unit. The total proceeds of $465.7 million were used to pay down the credit facility and to establish funding for potential convertible debenture or 7 7/8% Senior Note redemptions under the “change of control” provisions.

In October 2009, North Atlantic Refinery Ltd. entered into an amended Supply and Offtake Agreement (“SOA”) with Vitol Refining S. A. (“Vitol”), an international crude oil trading company, for an initial 2 year term effective November 1, 2009. This agreement requires the ownership of the crude oil and other feedstocks and substantially all of the refined product inventory at the refinery be retained by Vitol and also grants Vitol the exclusive rights and obligations to provide and deliver feedstock to the refinery and to purchase substantially all refined products produced by the refinery.  This arrangement provides Harvest with financial support for its crude oil purchase commitments as well as working capital financing for its inventories of crude oil and substantially all refined products held for sale.  The amendments increased the amount of working capital financing available, reduced the cost of financing inventory and other working capital, and increased the prices realized for product sales.  For more information on the SOA, see the description in our Annual Information Form for the year ended December 31, 2009 as filed on SEDAR at www.sedar.com. Pursuant to the SOA, we estimate that Vitol held inventories of VGO and crude oil feedstock (both delivered and in-transit) valued at approximately $521.3 million at March 31, 2010 (as compared to $582.1 million at the end of 2009), which would have otherwise been assets of Harvest.

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SUMMARY OF QUARTERLY RESULTS

The following table and discussion highlights our First Quarter of 2010 relative to the preceding seven quarters:

	2010			2009											2008
(in $000’s except where noted)	Q1			Q4			Q3			Q2			Q1		Q4		Q3		Q2
Revenue, net of royalties	$	569,762		$	853,139		$	991,854		$	562,997		$	731,095	$	892,739	$	1,597,195	$	1,622,079
Net (loss) income	$	(48,795	)	$	(13,022	)	$	(713,697	)		(265,779	)	$	56,864	$	78,640	$	295,788	$	(162,063	)
Per Trust Unit, basic(1)	$	(0.18	)	$	(0.07	)	$	(3.95	)	$	(1.59	)	$	0.36	$	0.50	$	1.93	$	(1.07	)
Per Trust Unit, diluted(1)	$	(0.18	)	$	(0.07	)	$	(3.95	)	$	(1.59	)	$	0.36	$	0.50	$	1.73	$	(1.07	)
Cash from operating activities	$	80,160		$	76,999		$	98,979			75,879		$	221,745	$	183,740	$	133,493	$	210,534
Per Trust Unit, basic	$	0.29		$	0.41		$	0.55		$	0.45		$	1.40	$	1.18	$	0.87	$	1.39
Per Trust Unit, diluted	$	0.29		$	0.41		$	0.55		$	0.45		$	1.28	$	1.10	$	0.84	$	1.26
Distributions per Unit, declared	$	-		$	0.05		$	0.15		$	0.15		$	0.65	$	0.90	$	0.90	$	0.90
Total long-term financial debt(2)	$	1,090,137		$	1,525,006		$	2,148,912		$	2,216,452		$	2,373,925	$	2,352,196	$	2,284,664	$	2,105,998
Total assets	$	4,402,329		$	4,404,912		$	4,423,802		$	5,296,596		$	5,785,269	$	5,745,407	$	5,659,227	$	5,637,879

(1) 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.

(2) Include current portion of Convertible Debentures

Net revenues are comprised of revenues net of royalties from our Upstream operations as well as sales of refined products from our Downstream operations.  Throughout the first three quarters of 2008, net revenues were the highest in Harvest’s history due to strong commodity prices, however the significant decrease in commodity prices in the Fourth Quarter of 2008 and throughout 2009 coupled with the refinery turnaround in the Second Quarter of 2009 and the fire in the First Quarter of 2010 resulted in a significant decrease in net revenues.

Net (loss) income reflects both cash and non-cash items. Changes in non-cash items, including future income tax, DD&A expense, unrealized foreign exchange gains and losses, unrealized gains on risk management contracts, goodwill impairment and Trust Unit right compensation expense cause net (loss) income to vary significantly from period to period.  In the Third Quarter of 2009, a goodwill impairment charge of $677.6 million relating to the Upstream reporting unit was recognized, while in the Second Quarter of 2009, a goodwill impairment charge of $206.5 million relating to the Downstream reporting unit was recognized.  Changes in the fair value of our risk management contracts have also contributed to the volatility in net (loss) income over the preceding eight quarters.  For these reasons, our net (loss) income does not reflect the same trends as net revenues or cash from operating activities, nor is it expected to.

Cash from operating activities is closely aligned with the trend in commodity prices for our Upstream operations and reflects the cyclical nature of the Downstream segment; it is also significantly impacted by changes in working capital.  In the First Quarter of 2009, cash from operating activities increased from the previous quarter mainly reflecting increased refining margins.  The decrease in the Second Quarter of 2009 and the subsequent recovery in the Third Quarter mainly reflect the reduction in product sales from the Downstream segment due to the completion of a planned turnaround.  The Fourth Quarter of 2009 decreased due to a planned reduction in refinery throughput to increase gasoline and distillate yields and minimize HSFO production to obtain more favorable economics as well as some unplanned downtime associated with maintenance work on the crude and platformer units.  The First Quarter of 2010 remained comparable with the previous quarter due to a further reduction in refinery throughput resulting from the unplanned downtime as a consequence of the fire in January, partially offset by an increase in realized prices in the Upstream segment.

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Total debt has remained relatively stable until the Fourth Quarter of 2009, reflecting moderate acquisition activity, offset by the issuance of Trust Units in the Second Quarter of 2009, and a net surplus of cash from operating activities over distributions to Unitholders.  Total debt decreased significantly in the Fourth Quarter of 2009 and then again in the First Quarter of 2010, reflecting the repayments of the bank loan and the redemption of the convertible debentures and senior notes; these payments were funded through two capital injections from KNOC Canada Ltd. totaling $1,065.7 million.

Total assets have also remained relatively stable until the Second Quarter of 2009.  The stability reflects moderate acquisition activity offset by a reduction in net book value associated with depletion and depreciation charges.  In the Second Quarter of 2009, total assets decreased due to recording an impairment charge associated with the Downstream reporting unit’s goodwill, and then in the Third Quarter of 2009, a further decrease in total assets occurred resulting from a further impairment charge associated with the Upstream reporting unit’s goodwill.

OUTLOOK

During the first quarter of 2010, the repositioning of Harvest as a growth oriented, integrated, oil and gas company progressed considerably. A $600 million equity issuance at the end of 2009 along with the $466 million equity issuance in January 2010, both to KNOC, strengthened the balance sheet and positioned the company for growth with an expanded internal capital investment program and greater consideration of acquisition opportunities.

Currently the economic environment is mixed for Harvest with strong crude oil and natural gas liquids prices offset by weaker natural gas prices and refining margins. We anticipate that we will continue to see a volatile commodity price environment in 2010. With an oil-weighted upstream business and assuming that crude oil prices remain strong, Harvest should reflect strong cash flow in 2010 relative to 2009.

Our upstream operational performance has been strong in the first quarter with production exceeding our expectations and operating costs being less than expected. We continue to anticipate that our upstream production will average approximately 36,000 bbls/d of liquids and 80,000 mcf/d of natural gas (approximately 50,000 boe/d) and continue to feel comfortable with that guidance given the strong start to the year. We also continue to project our operating costs to be approximately $14.00/boe.  General and administrative costs are experiencing a somewhat upward pressure relative to our guidance of $1.80/boe due to the introduction of a new long term incentive program, our expanded capital program and additional costs associated with the KNOC acquisition. It should be noted that the new long-term incentive program is expected to replace our previous restricted unit and unit appreciation right program. Harvest has no outstanding options, performance warrants or restricted units.

Upstream capital spending plans for 2010 remains at $320 million which includes the small acquisitions made in the first quarter of 2010. Larger acquisitions are not budgeted.  We expect to have an active drilling program with approximately 175 wells to be drilled over the course of the year. We also plan to continue with EOR projects in our larger oil reservoirs at Hay River, Bellshill Lake, Wainwright and Suffield with planned spending of $26 million. We expect our EOR projects to reduce decline rates for an extended period with improved recoveries due to maintaining reservoir pressures and the bolstering of traditional water flood projects with the introduction of chemical enhancements, such as alkaline surfactant polymers. In our upstream business, we will continue to evaluate opportunities to acquire producing oil and/or natural gas properties as well as offer selected properties for divestment to maintain and enhance our productive capabilities.

In our downstream operations (North Atlantic), capital spending will be focused on maintenance activities and increased discretionary profit improvement investments to improve reliability, increase throughput, enhance margins and reduce operating costs. We currently anticipate spending approximately $150 million on capital projects, including $78 million for the Debottleneck Projects. The Debottleneck Projects are a suite of investments estimated to cost a total of US$310 million over the course of 2010 and 2011. An additional $60 million will be spent in 2010 on catalyst and turnaround costs.

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North Atlantic experienced a production upset due to a fire in the hydrocracking unit and a consequential shutdown of the refinery on January 7th, 2010.  We are currently operating at near capacity subsequent to restoration of the operation of all units, which was completed before the end of March. Full year throughput is projected to average 90,000 bpd of feedstock with a refined product yield of 45% distillates, 30% gasoline and 25% HSFO. We also project that operating costs and purchased energy costs will aggregate to $6.19 per bbl. The cash flow contribution from our marketing activities in the Province of Newfoundland and Labrador is expected to contribute approximately $27 million of incremental cash flow to the downstream operations.

While we do not forecast commodity prices nor refining margins, we may enter into commodity price risk management contracts from time-to-time to mitigate some portion of our price volatility with the objective of stabilizing our cash flow from operating activities.  The following table reflects the sensitivity of our 2010 cash flow from operating activities over the remaining nine months of the year to changes in the following benchmark prices:

	Assumption		Change		Impact on Cash Flow
WTI oil price (US$/bbl)	$	88.00	$	5.00	$	32 mm
CAD/USD exchange rate	$	1.00	$	0.05	$	37 mm
AECO daily natural gas price	$	4.25	$	1.00	$	20 mm
Refinery crack spread (US$/bbl)	$	5.00	$	1.00	$	28 mm
Upstream operating expenses (per boe)	$	13.35	$	1.00	$	14 mm

Overall, we expect that based on current commodity price expectations, our 2010 cash from operating activities will be sufficient to fund our planned capital expenditures and continue to reduce bank debt.

Subsequent to the end of the first quarter, Harvest has completed the restructuring of the business into a corporate form. With the current approximately $3 billion of tax pools along with the tax shield associated with ongoing capital investment, we do not expect to pay any income tax in 2010.

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 are settled and when these activities are recognized for accounting purposes. Changes in these estimates could have a material impact on our reported results.  These estimates are described in detail in our MD&A for the year ended December 31, 2009 as filed on SEDAR at www.sedar.com.  There have been no significant changes to any of our critical accounting estimates in our consolidated financial statements for the three months ended March 31, 2010 from those described in our annual MD&A.

RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

International Financial Reporting Standards

In February 2008, the CICA Accounting Standards Board (“ASB”) announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards (“IFRS”) commencing January 1, 2011 which will require comparative IFRS information for the 2010 year end.

In July 2009, the International Accounting Standards Board (“IASB”) issued an amendment with additional exemptions for first time adopters of IFRS to enable an entity to measure exploration and evaluation assets at the amount determined under the entity’s previous accounting principles and it also provides for the measurement of oil and gas assets in the development or production phase, among other things, by allocating the amount determined by the entity’s previous accounting principles to the underlying assets on a pro rata basis using reserve volumes or reserve values at the date of transition.

We have staffed a project team with regular reporting to our senior management team and to the Audit Committee of the Board of Directors to ensure that we meet the IFRS transition requirements for 2011. The IFRS project team has developed an IFRS Transition Plan that consists of four key phases:

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1. Diagnostic phase – an initial assessment of the differences between Canadian accounting standards and IFRS, Planning, Assessment, Implementation and Training.

2. Planning phase – development of a project plan that includes assignment of roles and responsibilities, timeline and budget.

3. Assessment phase – a detailed comparison of the IFRS and Canadian standards to identify all applicable differences, as well as exemptions for first time adopters and expected changes to the relative IFRS standards. An assessment is then done on the impact on our accounting policies; information technology and data systems; business processes and data requirements; internal control over financial reporting, disclosure controls and procedures; financial reporting expertise and business activities that may be influenced such as debt covenants, capital requirements and compensation arrangements.

4. Implementation phase – preparing transitional opening IFRS financial statements; implementing accounting policy changes; implementing and testing data, process, system and control changes; training.

We are currently involved in the assessment phase of the project. We have completed the detailed analysis of the differences for most elements of our financial statements and are currently working with representatives from the various operational areas to select accounting policies and assess the impact of the differences on the data requirements, business processes, financial systems and internal controls. We have commenced our training of key employees through this process as well.  Korea is on the same IFRS conversion schedule as Canada and as a result we must reassess the accounting policies that we have initially selected to ensure that they align with KNOC’s policy choices. At this stage in the project, the full impact of adopting IFRS on Harvest’s financial position and future results can not be determined; however, the most significantly impacted areas to date are property, plant and equipment and impairment of assets.

OPERATIONAL AND OTHER BUSINESS RISKS

For a detailed discussion of our operational and other business risks, please refer to our MD&A for the year ended December 31, 2009 as filed on SEDAR at www.sedar.com.

CHANGES IN REGULATORY ENVIRONMENT

For a detailed discussion of the most recent changes to our regulatory environment, please refer to our MD&A for the year ended December 31, 2009 as filed on SEDAR at www.sedar.com.

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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