Harvest Operations 6-K Harvest Operations Announces Acquisition of the Blackgold

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s discussion and analysis (“MD&A”) of the financial condition and results of operations of Harvest Operations Corp. should be read in conjunction with the unaudited interim consolidated financial statements of Harvest Operations Corp. for the three and six months ended June 30, 2010.  The information and opinions concerning our future outlook are based on information available at August 6, 2010.

On December 22, 2009, KNOC Canada Ltd. (“KNOC Canada”), a wholly owned subsidiary of Korea National Oil Corporation (“KNOC”), purchased all of the issued and outstanding trust units of Harvest Energy Trust (the “Trust) and applied December 31, 2009 as the deemed acquisition date. The acquisition of all the issued and outstanding trust units of the Trust resulted in a change of control in which KNOC Canada became the sole unitholder of the Trust.

On May 1, 2010, an internal reorganization was completed pursuant to which the Trust was dissolved and the Trust’s wholly owned subsidiary and manager of the Trust, Harvest Operations Corp., was amalgamated into KNOC Canada to continue as one corporation under the name Harvest Operations Corp (“Harvest” or the “Company”). The carrying values of Harvest’s assets and liabilities were determined from the existing carrying values of KNOC Canada’s assets and liabilities and therefore reflect the fair values established through the purchase.

KNOC Canada was incorporated on October 9, 2009 and did not have any results from operations or cash flows in the period from October 9, 2009 to the deemed acquisition date of December 31, 2009 aside from capital injections from Korea National Oil Corporation to finance the purchase of the Trust. As KNOC Canada acquired the Trust on the deemed acquisition date of December 31, 2009 the Company’s financial statements for the interim period ended June 30, 2010 do not include prior year comparative information. Unaudited pro forma consolidated results of operations have been included in this MD&A to reflect the impact of the acquisition of the Trust, had the acquisition occurred on January 1, 2009.

In this MD&A, reference to "Harvest", “Company”, "we", "us" or "our" refers to Harvest Operations Corp. 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 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 and Cash From Operations are also non-GAAP measures and are commonly used for comparative purposes in the petroleum and natural gas and refining industries to reflect operating results before items not directly related to operations.  This information may not be comparable to similar measures by other issuers.

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FORWARD-LOOKING INFORMATION

This MD&A highlights significant business results and statistics from our consolidated financial statements for the three and six months ended June 30, 2010 and the accompanying notes thereto.  In the interest of providing our investors 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.

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.

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SELECTED INFORMATION

The table below provides a summary of our financial and operating results for the three and six months ended June 30, 2010.

	Three Months Ended			Six Months Ended
FINANCIAL ($000s except where noted)	June 30, 2010			June 30, 2010
Revenue, net (1)		1,024,896			1,594,658
Cash From Operating Activities		122,335			200,469
Net Income (Loss)(2)		18,203			(21,036	)
Bank debt		182,421			182,421
77/8% Senior debt		224,744			224,744
Convertible debentures(3)		770,780			770,780
Total financial debt(3)		1,177,945			1,177,945
Total Assets		4,758,472			4,758,472
UPSTREAM OPERATIONS
Total daily sales volumes (boe/day)		49,597			49,886
Operating Netback ($/boe)	$	29.68		$	32.95
Capital asset additions (excluding acquisitions)		52,314			165,843
Property and business acquisitions (dispositions), net		(726	)		30,236
Abandonment and reclamation expenditures		2,367			8,017
DOWNSTREAM OPERATIONS
Average daily throughput (bbl/d)		94,833			68,073
Average Refining Margin (US$/bbl)		8.56			5.86
Capital asset additions		8,459			17,142

(1) Revenues are net of royalties.

(2) Net Income (loss) includes a future income tax recovery of $15.1 million and $20.0 million for the three and six months ended June 30, 2010 respectively and an unrealized net gain from risk management activities of $2.2 million and $2.3 million for the three and six months ended June 30, 2010.

(3) Includes current portion of convertible debentures.

REVIEW OF OVERALL PERFORMANCE

Consolidated cash flow from operating activities was $122.3 million and $200.5 million for the three and six months ended June 30, 2010, representing and increase of $44.1 million over the first quarter of 2010.  This increase is primarily due to an increase in contribution from our Downstream operations of $66 million offset by a decrease in contribution from our Upstream operations of $28.8 million.

In January 2010, the Trust received a capital injection from KNOC Canada 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. As at June 30, 2010, our bank borrowings totaled $182.4 million with $317.6 million of undrawn credit lines available.

Upstream Operations

Upstream operations contributed $122.3 million of cash in the second quarter of 2010 compared with the first quarter contribution of $151.2 million. This decrease is predominantly due to lower commodity prices for oil and natural gas. Second quarter 2010 sales volumes were down marginally by 581 boe/d compared to the first quarter 2010, with the main decreases in natural gas and natural gas liquids as a result of third party plant processing constraints arising from power outages and turnarounds.  Second quarter 2010 operating costs totaled $68.3 million, an increase of $4.1 million as compared to $64.3 million incurred in the first quarter of 2010. The increase in operating costs during the second quarter was primarily due to the $5.6 million increase in power and fuel costs, before realized gains from electricity risk management contracts, which resulted from the 97% increase in the average Alberta Power Pool electricity price. Second quarter upstream capital spending of $52.3 million includes the drilling of 13 (net 10.8) wells with a success ratio of 100%.

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Downstream Operations

Downstream operations contributed $28.7 million of cash in the second quarter reflecting an average refining margin of US$8.56/bbl.  The negative cash flow of $8.6 million for the six months ended June 30, 2010 is a consequence of the unplanned shutdown in the first three months of the year due to a fire in January in the Isomax and surrounding units and the resulting repairs.  The average daily throughput for the three and six months ended June 30, 2010 was 94,833 bbl/d and 68,073 bbl/d; the throughput is lower than the capacity of 115,000 bbl/d as a result of the unplanned shutdown in the first three months of the year due to the fire in January; production units resumed operations early in the second quarter following the completion of repairs. Operating costs were $24.5 million in the second quarter of 2010 and were $2.84/bbl of throughput and $49.7 million for the six months ended June 30, 2010 and were $4.03/bbl of throughput.  The higher average operating cost per throughput barrel for the six months ended June 30 reflects the impact of the higher maintenance costs and lower throughput in the first quarter.   Likewise, purchased energy costs were $3.13/bbl of throughput for the second quarter as compared to $3.45/bbl of throughput for the six months ended June 30, 2010, again reflecting the lower throughput volumes in the first quarter of 2010.  Capital expenditures totaled $8.4 million during the second quarter (YTD June 30, 2010- $17.1 million) including $3.7 million related to debottlenecking projects (YTD June 30, 2010- $9.6 million).

UPSTREAM OPERATIONS

Summary of Financial and Operating Results

	Three Months Ended June 30									Six Months Ended June 30
(in $000s except where noted)	2010			2009  (Pro Forma 2)			Change			2010			2009  (Pro Forma2)			Change
Revenues		245,566			222,115			11	%		517,297			405,035			28	%
Royalties		(41,200	)		(28,199	)		46	%		(82,956	)		(52,728	)		57	%
Net revenues		204,366			193,916			5	%		434,341			352,307			23	%
Operating		68,328			61,317			11	%		132,581			136,652			(3	)%
General and administrative		11,726			8,874			32	%		24,143			16,268			48	%
Transportation and marketing		2,068			3,584			(42	)%		4,275			6,516			(34	)%
Depreciation, depletion and accretion		110,379			119,904			(8	)%		221,603			240,544			(8	)%
Earnings (Loss) From Operations(1)		11,865			237			4,906	%		51,739			(47,673	)		209	%
Capital asset additions (excluding acquisitions)		52,314			33,391			57	%		165,843			142,101			17	%
Property and business acquisitions (dispositions), net		(726	)		(61,403	)		99	%		30,236			(60,728	)		150	%
Abandonment and reclamation expenditures		2,367			1,548			53	%		8,017			5,014			60	%
OPERATING
Daily sales volumes
Light / medium oil (bbl/d)		24,874			24,316			2	%		24,681			24,275			2	%
Heavy oil (bbl/d)		9,090			10,365			(12	)%		9,170			10,751			(15	)%
Natural gas liquids (bbl/d)		2,334			2,675			(13	)%		2,574			2,756			(7	)%
Natural gas (mcf/d)		79,797			92,335			(14	)%		80,769			93,870			(14	)%
Total		49,597			52,745			(6	)%		49,886			53,427			(7	)%

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

(2) The 2009 comparative financial statement values are based on the "proforma" financials of Harvest Operations Corp.; see Note 1 to the June 30, 2010 Consolidated Financial Statements.

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Commodity Price Environment

	June 30, 2010
Benchmarks	Three Months Ended		Six Months Ended
West Texas Intermediate crude oil (US$/bbl)		78.03		78.37
Edmonton light crude oil ($/bbl)		75.14		77.71
Bow River blend crude oil ($/bbl)		66.56		70.05
AECO natural gas daily ($ per mcf)		3.89		4.42
Canadian / U.S. dollar exchange rate		0.973		0.967

The average WTI benchmark price remained essentially flat in the first half of 2010. The average Edmonton light crude oil price (“Edmonton Par”) decreased as a result of third party refinery outages that occurred during the second quarter which resulted in an oversupply of light crude market volumes. The average AECO daily natural gas price for the three months ending June 30, 2010 was lower due to decreased demand resulting from increased storage levels, decreased economic activity and milder than normal weather during the heating season.

	2010
Differential Benchmarks	Q2			Q1
Bow River Blend differential to Edmonton Par	$	8.58		$	6.72
Bow River Blend differential as a % of Edmonton Par		11.0	%		8.4	%

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.

Realized Commodity Prices(1)

The following table summarizes our average realized price by product for the three and six months ended June 30, 2010:

	June 30, 2010
	Three Months Ended		Six Months Ended
Light  to medium oil ($/bbl)		68.78		71.53
Heavy oil ($/bbl)		56.51		61.26
Natural gas liquids ($/bbl)		60.68		60.25
Natural gas ($/mcf)		4.17		4.65
Average Realized price ($/boe)		54.41		57.29

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

The decrease in the average realized prices for oil and gas for the three months ended June 30, 2010 are consistent with the decreases in the benchmark prices and the increase in the Bow River Blend differential.

Sales Volumes

The average daily sales volumes by product were as follows:

	June 30, 2010
	Three Months Ended					Six Months Ended
	Volume		Weighting			Volume		Weighting
Light / medium oil (bbl/d) (1)		24,874		50	%		24,681		50	%
Heavy oil (bbl/d)		9,090		18	%		9,170		18	%
Natural gas liquids (bbl/d)		2,334		5	%		2,574		5	%
Total liquids (bbl/d)		36,298		73	%		36,425		73	%
Natural gas (mcf/d)		79,797		27	%		80,769		27	%
Total oil equivalent (boe/d)		49,597		100	%		49,886		100	%

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

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Average light/medium oil sales were increased during the three months ended June 30, 2010 reflecting new well sales at Hay, Loon Lake and Evi as well as sales from the acquisition of Redwater in March 2010. The increase at Hay was negatively impacted by power and pipeline outages.Our heavy oil sale increases are from new well sales at Lloyd offset by natural production declines, wet weather and a minor turnaround at Hayter East. Average natural gas sales decreased as a result of third party plant processing constraints arising from power outages and turnarounds impacting sales volumes primarily at Chedderville and Crossfield.

Revenues

	June 30, 2010
($000s)	Three Months Ended			Six Months Ended
Light / medium oil sales	$	155,678		$	319,535
Heavy oil sales		46,747			101,678
Natural gas sales		30,253			68,018
Natural gas liquids sales and other		12,888			28,066
Total sales revenue		245,566			517,297
Royalties		(41,200	)		(82,956	)
Net Revenues	$	204,366		$	434,341

Our revenue is impacted by changes to sales volumes, commodity prices and currency exchange rates.

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 second quarter of 2010, royalties as a percentage of gross revenue were 16.8% and aggregated to $41.2 million. .

Operating Expenses

	June 30, 2010
	Three Months Ended				Six Months Ended
($000s)	Total		Per boe		Total		Per boe
Power and fuel	$	18,671	$	4.13	$	31,716	$	3.51
Well servicing		11,328		2.51		24,245		2.69
Repairs and maintenance		10,199		2.26		20,838		2.31
Lease rentals and property tax		7,713		1.71		15,829		1.75
Processing and other fees		3,064		0.68		6,979		0.77
Labour - internal		5,484		1.22		11,738		1.30
Labour - contract		3,897		0.86		7,917		0.88
Chemicals		4,056		0.90		7,857		0.87
Trucking		2,578		0.57		4,683		0.52
Other		1,338		0.30		779		0.08
Total operating expenses	$	68,328	$	15.14	$	132,581	$	14.68
Transportation and marketing expense	$	2,068	$	0.46	$	4,275		0.47

Average per boe operating expenses have increased during the three months ended June 30, 2010 due to increasing power and fuel costs.  The increase in the power and fuel costs is mainly due to the increase in the Alberta Power Pool electricity price which rose to an average $80.56/MWh during the three months ended June 30, 2010.

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Power and fuel costs, comprised primarily of electric power costs, represented approximately 27% of our total operating costs during the three months ended June 30, 2010.  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. The following table details the electric power costs per boe before and after the impact of our price risk management program.

	June 30, 2010
($ per boe)	Three Months Ended			Six Months Ended
Electric power and fuel costs	$	4.13		$	3.51
Realized gains on electricity risk management contracts		(0.27	)		(0.02	)
Net electric power and fuel costs		3.86			3.49
Alberta Power Pool electricity price ($ per MWh)	$	80.56		$	60.72

Transportation and marketing expense 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.

Operating Netback

	June 30, 2010
($ per boe)	Three Months Ended			Six Months Ended
Revenues	$	54.41		$	57.29
Royalties		(9.13	)		(9.19	)
Operating expense		(15.14	)		(14.68	)
Transportation expense		(0.46	)		(0.47	)
Operating netback (1)	$	29.68		$	32.95

(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. The average operating netback for the three months ended June 30, 2010 has decreased due to lower realized commodity prices and higher operating costs.

General and Administrative (“G&A”) Expense

	June 30, 2010
($000s except per boe)	Three Months Ended		Six Months Ended
Total G&A	$	11,726	$	24,143
G&A per boe ($/boe)		2.60		2.67

For the three months ended June 30, 2010, G&A expense decreased primarily due to an insurance premium refund of $0.3 million and a rent credit adjustment of $0.2 million.  Generally, approximately 80% of our G&A expenses are related to salaries and other employee related costs. 

Depletion, Depreciation, Amortization and Accretion Expense (“DDDA&A”)

	June 30, 2010
($000s except per boe)	Three Months Ended		Six Months Ended
Depletion and depreciation	$	95,193	$	191,054
Depletion of capitalized asset retirement costs		8,927		18,033
Accretion on asset retirement obligation		6,259		12,516
Total depletion, depreciation and accretion	$	110,379	$	221,603
Per boe ($/boe)	$	24.46	$	24.54

Our overall DDA&A expense for the three months ended June 30, 2010 was relatively unchanged from the first quarter of 2010 largely as production volumes remained constant throughout the first half of the year.

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Capital Expenditures

	June 30, 2010
($000s)	Three Months Ended		Six Months Ended
Land and undeveloped lease rentals	$	10,495	$	10,665
Geological and geophysical		2,879		11,429
Drilling and completion		19,748		92,687
Well equipment, pipelines and facilities		16,225		45,730
Capitalized G&A expenses		2,835		5,011
Furniture, leaseholds and office equipment		132		321
Total development capital expenditures excluding acquisitions	$	52,314	$	165,843

Capital expenditures are down during the second quarter of 2010 as a result of drilling 13 gross wells (10.8 net) compared to drilling 80 gross wells (65.9 net) in the first quarter of 2010. The majority of the 2010 second quarter drilling activity consisted of three gross (3.0 net) wells at Loydminister Heavy Oil ($2.6 million), three gross (2.5 net) wells at SE Saskatchewan ($2.8 million), one gross (0.5 net) well at SE Alberta ($1.7 million), one gross (1.0 net) well at Crossfield  ($4.9 million), two gross (1.3 net) wells at Rimbey/Markerville ($2.2 million) and two gross (1.5 net) wells at Red Earth ($5.5 million).

During the second quarter of 2010 Harvest acquired lands at Red Earth ($6.2 million) and West Central Alberta ($3.9 million). These lands were acquired for future development and exploration purposes.

In the first half of 2010, Harvest had a 100% success rate for all wells drilled. The following summarizes Harvest’s participation in gross and net wells drilled during the three and six month ending June 30:

	June 30, 2010
	Three Months Ended				Six Months Ended
Area	Gross(1)		Net		Gross(2)		Net
Hay River		0.0		0.0		8.0		8.0
SE Alberta		1.0		0.5		7.0		3.6
Rimbey/Markerville		2.0		1.3		9.0		4.6
SE Saskatchewan		3.0		2.5		10.0		9.5
Red Earth		2.0		1.5		18.0		14.7
Suffield		0.0		0.0		5.0		5.0
Lloydminster Heavy Oil		3.0		3.0		23.0		21.0
Crossfield		1.0		1.0		3.0		2.9
Kindersley		0.0		0.0		6.0		4.7
Other Areas		1.0		1.0		4.0		2.7
Total wells		13.0		10.8		93.0		76.7

(1) Excludes 3 additional wells that we have royalties interest in.

(2) Excludes 4 additional wells that we have royalties interest in.

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 $4.0 million during the second quarter of 2010 as a result of accretion expense of $6.3 million and new liabilities recorded of $0.1 million, offset by $2.4 million of asset retirement liabilities settled.

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DOWNSTREAM OPERATIONS

Summary of Financial and Operational Results

	Three Months Ended June 30								Six Months Ended June 30
(in $000’s except where noted below)	2010		2009 (Pro Forma5)			Change			2010			2009 (Pro Forma5)		Change
Revenues		820,530		369,081			122	%		1,160,317			941,785		23	%
Purchased feedstock for processing and products purchased for resale (4)		731,778		322,855			127	%		1,062,351			704,692		51	%
Gross margin(1)		88,752		46,226			92	%		97,966			237,093		(59	)%
Costs and expenses
Operating		30,278		26,974			12	%		60,037			50,940		18	%
Purchased energy		27,040		11,161			142	%		42,470			27,768		53	%
Marketing		2,364		3,122			(24	)%		3,315			6,101		(46	)%
General and administrative		441		520			(15	)%		882			875		1	%
Depreciation and amortization		20,179		22,771			(11	)%		40,624			47,096		(14	)%
Earnings (Loss) From Operations(1)		8,450		(18,322	)		146	%		(49,362	)		104,313		(147	)%
Capital asset additions		8,459		19,929			(58	)%		17,142			26,833		(36	)%
Feedstock volume (bbl/day)(2)		94,833		52,808			80	%		68,073			78,410		(13	)%
Yield (000’s barrels)
Gasoline and related products		2,949		1,372			115	%		3,833			4,693		(18	)%
Ultra low sulphur diesel and jet fuel		3,548		1,830			94	%		4,629			5,324		(13	)%
High sulphur fuel oil		2,312		1,183			95	%		3,562			3,553		-
Total		8,809		4,385			101	%		12,024			13,570		(11	)%
Average refining gross margin (US$/bbl)(3)		8.56		6.50			32	%		5.86			12.51		(53	)%

(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.

(4) Purchased feedstock for processing and products purchased for resale includes inventory write-downs, net of reversals, of $2.2 million and $3.3 million for the three and six months ended June 30, 2010, respectively.

(5) The 2009 comparative financial statement values are based on the “pro-forma” financials of the Downstream operations of Harvest Operations Corp.; see Note 1 to the June 30, 2010 Consolidated Financial Statements

Overview of Downstream Operations

Our Downstream operations are composed of a 115,000 bpd medium gravity sour crude oil hydrocracking refinery and a retail and wholesale petroleum marketing business both located in the Province of Newfoundland and Labrador.  Our petroleum marketing business is composed of branded and unbranded retail and wholesale distribution and sales of gasoline, diesel, jet and other transportation fuels, as well as home heating fuels and the revenues from our marine services businesses.

The financial performance of our refinery reflects its throughput, feedstock selection, operating effectiveness, refining margins and operating costs.  Our refining margin is dependent on the sales value of the refined products produced and the cost of crude oil and other feedstocks purchased as well as the yield of refined products from various feedstocks.  We continuously evaluate the market and relative refinery values of several different crude oils and vacuum gas oils (“VGO”) to determine the optimal feedstock mix.  We analyze the refining margin for each refined product as well as our sales revenue relative to refined product benchmark prices and the WTI benchmark price.  With respect to feedstock costs, we analyze our price discounts relative to the WTI benchmark price and segregate crude oil sources by country of origin for reporting.

In 2010, we purchased substantially all of our refinery feedstock and sold our distillates, gasoline products and high sulphur fuel oil (“HSFO”), with the exception of products sold in Newfoundland through our petroleum marketing division, to Vitol Refining S.A. (“Vitol”) pursuant to the supply and offtake agreement (“SOA”).  Further details on the SOA are included under “Liquidity and Capital Resources”.

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The SOA with Vitol contains pricing terms that reflect market prices based on an average ten-day delay which results in our purchases from, and sales to, Vitol being priced on future prices as compared to pricing at the time of the delivery.  With the exception of the sales to Vitol, our refined products are sold at prices that reflect market prices at the time that the product is delivered to the purchaser.

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:

	June 30, 2010
	Three Months Ended			Six Months Ended
WTI crude oil  (US$/bbl)		78.03			78.37
Brent crude oil (US$/bbl)		79.51			78.40
Basrah Official Sales Price Discount (US$/bbl)		(1.58	)		(2.90	)
RBOB gasoline (US$/bbl/gallon)		91.07/2.17			89.63/2.13
Heating Oil (US$/bbl/gallon)		88.55/2.11			87.27/2.08
High Sulphur Fuel Oil  (US$/bbl)		69.25			69.99
Canadian / U.S. dollar exchange rate		0.973			0.967

The RBOB Gasoline crack spread averaged US$13.04/bbl in the second quarter of 2010 and US$11.26/bbl for the six months ended June 30, 2010.  For the three and six months ended June 30, the Heating Oil crack spread averaged US$10.52/bbl and US$8.90/bbl, respectively.  The HSFO benchmark price averaged US$8.78/bbl less than WTI in the second quarter of 2010 and US$8.38/bbl less than WTI in the six months ended June 30, 2010.

During the three months ended June 30, 2010, the Canadian/U.S. dollar exchange rate remained strong..  The strengthening of the Canadian dollar in 2010 has slightly decreased the contribution from our Downstream operations as substantially all of its gross margin, cost of purchased energy and marketing expense are denominated in U.S. dollars.

Summary of Gross Margin

The following table summarizes our Downstream gross margin for the three and six months ended June 30, 2010 segregated between refining activities and petroleum marketing and other related businesses.

	June 30, 2010
	Three Months Ended						Six Months Ended
(000’s of Canadian dollars)	Refining		Marketing		Total		Refining		Marketing		Total
Sales revenue(1)		791,287		150,003		820,530		1,102,327		266,436		1,160,317
Cost of feedstock for processing and products for resale(1)		715,385		137,153		731,778		1,027,708		243,089		1,062,351
Gross margin(2)		75,902		12,850		88,752		74,619		23,347		97,966
Average refining gross margin (US$/bbl)		8.56						5.86

 (1) Downstream sales revenue and cost of products for processing and resale are net of intra-segment sales of $120.8 million and $208.5 million for the three and six months ended June 30, 2010, respectively,  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 June 30, 2010, our refining gross margin of $75.9 million reflects the return to normal operations after an unplanned shutdown in the first quarter as a consequence of a fire.  An insurance claim will be submitted to the Company’s insurers relating to the cost of the business interruption loss incurred in the First Quarter due to the unplanned shutdown. The contribution from the marketing operations is fairly consistent from month to month but may be impacted by seasonal demand and other factors.  The unplanned shutdown of the refinery units in early January of 2010 had a negative impact on the revenue from the marine operations during the first three months of 2010, however, revenues improved in the second quarter with the start-up of the refinery units in early April.

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Refinery Sales Revenue

A comparison of our refinery yield, product pricing and revenue for the three and six months ended June 30, 2010 is presented below:

	June 30, 2010
	Three Months Ended							Six Months Ended
	Refinery Revenues		Volume			Sales Price(1)		Refinery Revenues		Volume			Sales Price(1)
	(000’s of Cdn $)		(000s of bbls)			(US$ per bbl/ US$ per US gal)		(000’s of Cdn $)		(000s of bbls)			(US$ per bbl/ US$ per US gal)
Gasoline products		275,023		3,025			88.46/2.10		360,387		3,972			87.74/2.09
Distillates		351,691		3,838			89.16/2.12		463,998		5,053			88.80/2.11
High sulphur fuel oil		164,573		2,331			68.70		277,942		3,861			69.61
		791,287		9,194			83.74		1,102,327		12,886			82.72
Inventory adjustment				(385	)						(862	)
Total production				8,809							12,024
Yield (as a % of Feedstock) (2)				102	%						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.

For the three months ended June 30, 2010, our refinery yield was comprised of 34% gasoline products, 40% distillates and 26% HSFO and for the six months ended June 30, 2010 our yield was comprised of 32%, 38% and 30% for the same products respectively.  The change in product yields is a consequence of the start-up of production units and the return to normal operations following the completion of repairs for an unplanned shutdown in early January in the first quarter.

In the second quarter of 2010, our average refined product sales price was US$83.74/bbl, a premium of US$5.71/bbl over WTI.  For the six months ended June 30, 2010 our average refined product sales price was US$82.72/bbl, a premium of US$4.35/bbl over WTI.

During the second quarter of 2010, the average sales price of our gasoline products of US$88.46/bbl was a US$10.43/bbl premium to the average WTI price as compared to the RBOB benchmark crack spread of US$13.04/bbl.  The US$2.61/bbl differential between our gasoline products crack spread and the benchmark crack spread is a consequence of transportation costs and timing of sales under the SOA.

For the six months ended June 30, 2010 our average sales price for gasoline products of US$87.74 was a US$9.37/bbl premium to the average WTI price as compared to the RBOB benchmark crack spread of US$11.26/bbl.  This US$1.89/bbl differential between our gasoline products crack spread and the benchmark crack spread is a consequence of transportation costs, the timing of sales under the SOA and limited sales during the first quarter.

During the second quarter of 2010, the average sales price for our distillate products of US$89.16/bbl was a US$11.13/bbl premium to the average WTI price as compared to a US$10.52/bbl premium for the Heating Oil benchmark price over WTI.  The US$0.61/bbl differential between our distillate products crack spread and the benchmark Heating Oil crack spread reflects the higher quality distillate products produced and sold by our refinery as compared to the quality of the Heating Oil benchmark pricing.  The distillate premium realized by our refinery is also impacted by transportation costs and the timing of sales under the SOA.

During the six months ended June 30, 2010 the average sales price for our distillate products of US$88.80/bbl was a US$10.43/bbl premium to the average WTI price as compared to a US$8.90 premium for the Heating Oil benchmark price over WTI.  The US$1.53/bbl differential between our distillate products crack spread and the Heating Oil benchmark crack spread reflects the higher quality distillate products produced and sold by our refinery as compared to the quality of the Heating Oil benchmark pricing and the timing of sales under the SOA, offset by transportation costs.  In addition, sales of distillate products were limited in the first quarter as a result of the unplanned shutdown of the refinery units.

During the second quarter of 2010, the average sales price of our HSFO of US$68.70/bbl was a US$9.33/bbl discount to the average WTI price as compared to an US$8.78/bbl discount for the HSFO benchmark pricing from WTI.  The higher HSFO discounts realized by the refinery for the second quarter are a result of transportation costs and timing of sales under the SOA.

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For the six months ended June 30, 2010 the average sales price of our HSFO of US$69.61/bbl was a US$8.76/bbl discount to WTI as compared to the HSFO benchmark pricing discount of US$8.38/bbl.  The higher HSFO discounts realized by the refinery for the six months ended June 30 are a result of transportation costs, timing of sales under the SOA and limited sales of HSFO in the first quarter as a consequence of the fire in January.

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 VGO’s 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 SOA, the ten day delay in pricing pursuant to the SOA 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 April of 2010, the OSP discount was set relative to WTI, however, in April 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 to the benchmark pricing 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 ten weeks.  As well, remaining production units were shutdown at the end of January as a result of unfavorable economics.  Operations resumed in early April 2010 and second quarter results reflect fairly normal refinery operations.

A comparison of crude oil and VGO feedstock processed for the three and six months ended June 30, 2010 is presented below:

	June 30, 2010
	Three Months Ended						Six Months Ended
	Cost of Feedstock		Volume		Cost per Barrel(1)		Cost of Feedstock		Volume		Cost per Barrel(1)
	(000’s of Cdn $)		(000s of bbls)		(US$/bbl)		(000’s of Cdn $)		(000s of bbls)		(US$/bbl)
Iraqi		490,136		6,539		72.93		669,592		8,788		73.68
Russian		92,971		1,368		66.13		205,554		2,726		72.92
Venezuelan		15,897		194		79.73		20,381		256		76.99
Crude Oil Feedstock		599,004		8,101		71.95		895,527		11,770		73.57
Vacuum Gas Oil		43,209		529		79.48		45,070		551		79.10
		642,213		8,630		72.41		940,597		12,321		73.82
Net inventory adjustment (2)		21,398						17,483
Additives and blendstocks		49,541						66,314
Inventory write-down (recovery) (3)		2,233						3,314
		715,385						1,027,708

(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.

Throughput in the second quarter of 2010 was 94,833 bbl/d and and for the six months ended June 30, 2010 throughput averaged 68,073 bbl/d.  Average daily throughput in 2010 is less than the nameplate capacity of 115,000 bbl/d for our refinery as a result of the unplanned shutdown of the refinery units in January month.  Operations resumed in the second quarter following the start-up of the production units in early April.  Daily average throughput continued to be slightly lower than capacity during the second quarter as a result of ongoing maintenance.

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As is normal business practice, the WTI component of our feedstock cost is operationally hedged under the SOA with 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 results 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 and six months ended June 30, 2010, this operational hedging resulted in reductions to the cost of our feedstock of US$15.3 million and US$18.4 million, respectively.

The cost of our crude oil feedstock averaged US$71.95/bbl during the second quarter of 2010 representing a US$6.08/bbl discount to WTI.  The US$6.08/bbl discount is comprised of a US$3.10/bbl quality discount, plus a US$1.73/bbl operational hedging gain and a US$1.25/bbl credit relating to timing under the SOA with Vitol.  The cost of our crude oil feedstock averaged US$73.57/bbl for the six months ended June 30, 2010 representing a US$4.80/bbl discount to WTI.  The US$4.80/bbl discount is comprised of a US$2.43/bbl quality discount, plus a US$1.42 operational hedging gain and a US$0.95/bbl credit relating to timing under the SOA with Vitol.

The average cost of purchased VGO during the second quarter of 2010 was US$79.48/bbl representing a premium of US$1.45/bbl relative to the WTI.  The premium paid in the second quarter of 2010 is comprised of a US$5.53/bbl pricing premium relative to WTI offset by a US$1.66/bbl credit relating to timing under the SOA with Vitol and a US$2.42/bbl operational hedging gain.  The average cost of purchased VGO for the six months ended June 30, 2010 was US$79.10/bbl representing a premium of US$0.73/bbl relative to the WTI.  The premium paid is comprised of a US$5.18/bbl pricing premium relative to WTI offset by a US$2.87/bbl operational hedging gain and a US$1.58/bbl credit relating to timing under the SOA with Vitol.

Included in the additives and blendstocks for the three and six months ended June 30, 2010 is the cost of products purchased for further refining into finished products and products purchased for resale to the local market.

Operating Expenses

The following summarizes the operating costs from the refinery and marketing division for the three and six months ended June 30, 2010:

	June 30, 2010
	Three Months Ended						Six Months Ended
(000’s of Cdn dollars)	Refining		Marketing		Total		Refining		Marketing		Total
Operating costs		24,509		5,769		30,278		49,653		10,384		60,037
Purchased energy		27,040		-		27,040		42,470		-		42,470
		51,549		5,769		57,318		92,123		10,384		102,507

During the three and six months ended June 30, 2010, refining operating costs were $2.84/bbl and $4.03/bbl of throughput, respectively.  The higher operating costs per barrel for the six months period includes the higher maintenance costs related to the fire repairs combined with a reduction in throughput.  Included in the marketing division operating expenses for the second quarter are additional maintenance costs incurred for the marine operations.

Purchased energy, consisting of low sulphur fuel oil and electricity, is required to provide heat and power to refinery operations.  Our purchased energy for the three months ended June 30, 2010 was $3.13/bbl of throughput and for the six months ended June 30, 2010 our purchased energy was $3.45/bbl of throughput.  In the second quarter of 2010, we purchased approximately 343,000 barrels of fuel oil at an average price of US$69.76/bbl.  Likewise in the six months ended June 30, 2010 we purchased approximately 520,000 barrels at an average price of US$72.09/bbl.

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Marketing Expense and Other

During the three months ended June 30, 2010, marketing expense was comprised of $0.3 million of marketing fees (six months ended June 30, 2010 - $0.3 million), based on $0.02/bbl to acquire feedstock and $2.1 million (six months ended June 30, 2010 - $3.0 million) of TVM charges both pursuant to the terms of the SOA.  The higher TVM charge in the second quarter is mainly the result of increased purchased feedstock volume.  As at June 30, 2010, Harvest had commitments totaling approximately $502.5 million in respect of future crude oil feedstock purchases and related transportation from Vitol.

Capital Expenditures

Capital spending for the three and six months ended June 30, 2010 totaled $8.4 million and $17.1 million, respectively, relating to various capital improvement projects including $3.7 million of expenditures in the second quarter for the debottlenecking projects and $9.6 million of expenditures related to the debottlenecking projects for the six months ended June 30.

Depreciation and Amortization Expense

The following summarizes the depreciation and amortization expense for the three and six months ended June 30, 2010:

June 30, 2010

Three Months Ended

Six Months Ended

(000’s of Cdn dollars)

Refining

Marketing

Total

Refining

Marketing

Total

Tangible assets

19,340

839

20,179

38,913

1,711

40,624

The process units are amortized over an average useful life of 20 to 30 years.

RISK MANAGEMENT, FINANCING AND OTHER

Cash Flow Risk Management

Harvest employs an integrated approach to cash flow risk management strategies whereby our cash flow from producing crude oil in western Canada is financially integrated with our requirement to purchase crude oil feedstock for our Downstream operations even though the crude oil produced in western Canada does not physically flow to our refinery in Newfoundland.  As a result, our 2010 cash flow at risk is comprised of approximately 32,000 bbls/d of refined product price exposure, 57,000 bbls/d of refined product crack spread exposure and 68,000 mcf/d of net western Canadian natural gas price exposure.

The details of our commodity price contracts outstanding at June 30, 2010 are included in the notes to our consolidated financial statements which are also filed on SEDAR at www.sedar.com.

For the three months ended June 30, 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 as well as electricity price swap contracts for 5.0 MWh from January to December 2011 at an average price of $45.85 per MWh. Our electricity price contracts realized gains of $1.2 million and $0.2 million for the three and six months ended June 30, 2010, respectively.

As at June 30, 2010, the mark-to-market value on our electric power contracts aggregated to $0.3 million.

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Interest Expense

	June 30, 2010
($000s)	Three Months Ended		Six Months Ended
Interest on short term debt
Bank loan	$	-	$	1,370
Convertible debentures		312		93
Senior notes		-		30
Total interest on short term debt		312		1,493
Interest on long term debt
Bank loan		1,524		1,524
Convertible debentures		12,504		26,214
Senior notes		3,950		8,326
Total interest expense on long term debt	$	17,978	$	36,064
Total interest expense	$	18,290	$	37,557

Total Interest expense for three and six months ended June 30, 2010 including the amortization of related financing costs was $18.3 million and $37.6 million, respectively.

Interest expense on our bank loan for the three months ended June 30, 2010 reflects amended terms on our revolving credit facility that was amended on April 30, 2010 whereby the floating rate increased from 70 basis points over bankers’ acceptances for Canadian dollar borrowings to 200 basis points. The Revolving Credit Facility was required to be amended as the KNOC Canada acquisition triggered the “change of control” provision. During the three months ended June 30, 2010, interest charges on bank loans reflected an average interest rate of 1.95%. The increased floating rate in the three months ended June 30, 2010 was offset against a lower balance outstanding throughout the second quarter as a result of the $465.7 million equity issuance to KNOC Canada in January 2010 that was partially used to pay down the Bank Loan.

During the first quarter of 2010, the KNOC Canada acquisition triggered the “change of control” provisions included within the convertible debentures and the 77/8% senior notes indentures which required the Company to make an offer to purchase these instruments for cash consideration of 101% of the principal amount thereof plus accrued and unpaid interest. By March 4, 2010 all of the redemption offers had expired and $156.4 million principal amount of convertible debentures and US$40.4 milion principal amount of 77/8% senior notes were redeemed; see the Liquidity and Capital Resources section below for further details related to the redemptions. This reduction of outstanding principal amount has led to a decrease in interest expense on the convertible debentures and senior notes for the three months ended June 30, 2010.

The bank loan, convertible debentures and 77/8% senior notes are recorded at amortized cost and as such interest is calculated using the effective interest method. Therefore, total interest includes non-cash interest income of $3.8 million and $4.7 million for the three and six months ended June 30, 2010 relating to the amortization of the premium on the convertible debentures and 77/8% senior notes and the fees incurred on the credit facility.

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 losses of $5.6 million and $5.2 million for the three and six months ended June 30, 2010 respectively, have resulted from the settlement of U.S. dollar denominated transactions.  At June 30, 2010 the Canadian dollar has weakened compared to March 31, 2010 and December 31, 2009 resulting in an unrealized foreign exchange gain of $3.0 million and loss of $3.4 million for the three and six months ended June 30, 2010.

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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 three and six months ended June 30, 2010, the weakening of the Canadian dollar relative to the U.S. dollar resulted in a $46.9 million and $20.0 million net cumulative translation gain as the stronger U.S. dollar results in an increase in the relative value of the net assets in our Downstream operations.

Future Income Tax

As KNOC Canada acquired the Trust on the deemed acquisition date of December 31, 2009, the opening future income tax liability is calculated as part of the purchase price allocation recorded at that date.  The opening future income tax liability of $211.2 million represents a tax liability driven by the excess book over tax value of net assets.  For six months ended June 30, 2010, we have recorded a future income tax reduction of $20.0 million to reflect the changes in the temporary differences. At the end of the six months ended June 30 2010, Harvest had a net future income tax liability on the balance sheet of $191.1 million comprised of a $89.0 million future income tax liability for the downstream corporate entities and a future income tax liability of $102.1 million for the upstream entities.

Income Tax Assessment

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; the undertakings, which are mutual requests for additional information, have been completed on both sides..

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.  These obligations are of a recurring and consistent nature and impact cash flow in an ongoing manner.  As at June 30, 2010, we also have contractual obligations and commitments that are of a less routine nature as disclosed in the following table:

	Maturity
($000s)	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Long-term debt(1)	$	1,163,328	$	23,810	$	329,900	$	573,019	$	236,599
Interest on long-term debt(1)		234,308		38,771		128,242		60,003		7,292
Operating and premise leases		32,264		3,769		14,630		12,419		1,446
Purchase commitments(2)		36,099		34,282		1,817		-		-
Asset retirement obligations(3)		1,211,209		16,186		28,189		26,335		1,140,499
Transportation (4)		6,202		2,903		3,094		205		-
Pension contributions(5)		24,564		2,800		8,448		8,789		4,527
Feedstock commitments		502,471		502,471		-		-		-
Total	$	3,210,445	$	624,992	$	514,320	$	680,770	$	1,390,363

(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.

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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. 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. Refer to Note 18 of the unaudited interim June 30, 2010 financial statements for commitments related to subsequent acquisitions.

Off Balance Sheet Arrangement

As of June 30, 2010, we have no off balance sheet arrangements in place.

LIQUIDITY AND CAPITAL RESOURCES

Harvest is an integrated company with a declining asset base in our upstream operations and a “near perpetual” asset in our downstream operations.  As well as future petroleum and natural gas prices, our upstream operations rely on the successful exploitation of our existing reserves, future development activities and strategic acquisitions to replace existing production and add additional reserves.  With a prudent maintenance program, our downstream assets are expected to have a long life with additional growth in profitability available by upgrading the HSFO currently produced, enhancing our refining capability to handle a lower cost feedstock and/or expanding our refining throughput capacity.  Future development activities and acquisitions in our upstream business as well as the maintenance program in our downstream business will likely be funded by our cash flow from operating activities while we will generally rely on funding more significant acquisitions and growth initiatives from some combination of cash flow from operating activities, issuances of incremental debt and capital injections from KNOC. Should incremental debt not be available to us through debt capital markets, our ability to make the necessary expenditures to maintain or expand our assets may be impaired.  In our upstream business, it is not possible to distinguish between expenditures to maintain productive capacity and spending to increase productive capacity due to the numerous factors impacting reserve reporting and the natural decline in reservoirs and accordingly, maintenance capital is not disclosed separately.

During the latter part of 2009 and into the first quarter of 2010 we had seen an improvement in the price of oil and in the liquidity of the debt capital markets. During the second quarter of 2010, the global economic recovery has somewhat stabilized which resulted in a decrease in oil prices. In the first quarter, the state of the bank credit markets had also improved, supporting the renewal of our revolving credit facility at the end of April.  In addition both Standard and Poor’s Ratings Services (“S&P”) and Moody’s Investors Service upgraded our 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, as further discussed below, it is anticipated that we will have enough liquidity to fund future operations and forecasted capital expenditures.

During the three and six months ended June 30, 2010, cash flow from operating activities was $122.3 million and $200.5 million, respectively. Cash flow from operating activities before changes in non-cash working capital and asset retirement expenditures totaled $127.7 million and $217.6 million for the three and six months ended June 30, 2010 respectively. In January 2010, the Trust received a capital injection from KNOC Canada 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 $60.0 million and $213.2 million for capital expenditures and net asset acquisition activity for the three and six months ended June 30, 2010, respectively.  As at June 30, 2010, our bank borrowings totaled $182.4 million with $317.6 million of undrawn credit lines available.

The following table summarizes our capital structure as at June 30, 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 8, 9 and 10, respectively, to our interim consolidated financial statements for the period ended June 30, 2010 filed on SEDAR at www.sedar.com.

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SUMMARY OF CAPITALIZATION
(in million)	June 30, 2010			December 31, 2009
Revolving credit facility	$	182.4		$	428.0
77/8% senior notes due 2011 (US$209.6 million) (1)		223.1			262.8
Convertible debentures, at principal amount		757.8			914.2
Total Debt		1,163.3			1,605.0
Shareholder’s Equity
288,836,653 issued at June 30, 2010		2,887.3
242,268,801 issued at December 31, 2009					2,422.7
TOTAL CAPITALIZATION	$	4,050.6		$	4,027.7
FINANCIAL RATIOS
Secured Debt to Annualized EBITDA (2)		0.4			0.7
Total Debt to Annualized EBITDA (2) (3)		2.3			2.7
Secured Debt to Total Capitalization		5	%		11	%
Senior Debt to Total Capitalization		29	%		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 Canada.

KNOC Canada’s acquisition of Harvest Energy Trust 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 on May 1, 2010 and the redemption of some of our convertible debentures and 77/8% senior notes in the first quarter.

Credit Facility

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 77/8% 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 had unutilized borrowing capacity of $317.6 million based on our drawn amount as at June 30, 2010 of $182.4 million.  We have the option to increase the capacity limit from $500 million to $1.0 billion, without lender consent, by utilizing the accordion feature and securing additional capacity from an existing or new lender(s).  The financial covenants remain the same as in the past and are listed as:

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

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Convertible Debentures

The “change of control” provision included within the convertible debentures’ indetnures 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 Canada 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.  As 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.

77/8% Senior Notes

In October 2004, the Trust issued US$250 million of principal amount 77/8% senior notes and $209.6 million remain outstanding at June 30, 2010.  These 77/8% senior notes are unsecured, require semi-annual payments of interest and mature on October 15, 2011.

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 plus any accrued and unpaid interest. Harvest made this offer on January 20, 2010 and on February 16, 2010 the offer expired and US$40,434,000 principal amount was tendered, leaving a principal balance of US$209,566,000 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.

The most restrictive covenant of the 77/8% senior notes limits the incurrence of additional indebtedness if such issuance would result in an interest coverage ratio, as defined, of less than 2.5 to 1.0 and in respect of the incurrence of secured indebtedness, limits the amount to less than 65% of the present value of future net revenues from our proved petroleum and natural gas reserves discounted at an annual rate of 10%.  At December 31, 2009, 65% of the present value of the future net revenues from our proved petroleum and natural gas reserves discounted at an annual rate of 10% is approximately $1.9 billion. This covenant is recalculated on an annual basis, therefore, as at June 30, 2010 the calculation at December 31, 2009 remains in effect.

Supply and Offtake Agreement

Concurrent with the acquisition of  North Atlantic Refining Limited Partnership (“North Atlantic”) by Harvest in 2006, North Atlantic entered into a supply and offtake agreement (the “SOA”) with Vitol Refining S.A. ("Vitol"), and this agreement was amended and extended October 12, 2009; effective November 1, 2009. The SOA provides that the ownership of substantially all crude oil and other feed stocks and refined product inventories at the refinery be retained by Vitol and that Vitol be granted the exclusive right and obligation to provide crude oil feedstock and other feed stocks for delivery to the refinery as well as the exclusive right and obligation to purchase virtually all refined products produced by the refinery for export. The SOA also provides that Vitol will receive a time value of money amount (the "TVM") reflecting the cost of financing the working capital associated with the purchase of crude oil and other feed stocks and sale of refined products, as the SOA requires that Vitol retain ownership of the crude oil and other feed stocks until delivered through the inlet flange to the refinery as well as immediately take title to the refined products as they are delivered by the refinery through the inlet flange to designated storage tanks. Further, the SOA provides North Atlantic with the opportunity to share the incremental profits and losses resulting from the sale of products beyond the U.S. east coast markets.

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Pursuant to the SOA, we, in consultation with Vitol, request a certain slate of crude oil and other feed stocks and Vitol is obligated to provide the feed stocks in accordance with the request. The SOA includes a feedstock transfer pricing formula that aggregates the pricing for the feed stocks purchased as correlated to published future contract settlement prices, the cost of transportation from the source of supply to the refinery and the settlement cost or proceeds for related operational price risk management contracts plus a marketing fee. The purpose of these operational price risk management contracts is to convert the fixed price of crude oil and other feedstock purchases to floating prices for the period from the purchase date through to the date the refined products are sold to North Atlantic to allow "matching" of feedstock purchases to refined product sales, thereby mitigating the gross margin risk between the time feed stocks are purchased and the time refined products are sold.

The SOA requires that Vitol purchase and lift all refined products produced by the refinery, except for certain excluded refined products to be marketed by North Atlantic in the local Newfoundland market, and provides a product purchase pricing formula that aggregates a price based on the current Boston and New York City markets less the costs of transportation, insurance, port fees, inspection charges and similar costs incurred by Vitol, plus the TVM component.

The SOA is effective until November 1, 2011 and may be terminated by either party at any time thereafter by providing notice of termination no later than six months prior to the desired termination date or if the refinery is sold in an arm’s length transaction, upon 30 days notice prior to the desired termination date. Further, the SOA may be terminated upon the continuation for more than 180 days of a delay in performance due to force majeure but prior to the recommencing of performance. Upon termination of the entire agreement or the right and obligation to provide feed stocks, North Atlantic will be required to purchase the related feed stocks and refined product inventories, respectively, at the prevailing market prices.

Vitol is an indirect wholly-owned subsidiary of the Vitol Group, a privately owned worldwide marketer of crude oil providing oil trading and marketing services to upstream producers through to downstream retailers of petroleum products. The Vitol Group is one of the largest independent gasoline traders in the world. With headquarters in Rotterdam, the Netherlands and Geneva Switzerland, with trading entities in Houston, London, Bahrain and Singapore the Vitol Group has 24 hour coverage of all the world's oil markets. In the crude oil sector, the Vitol Group has developed a worldwide reputation as a reliable business partner.

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 made in 2009 to the SOA 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.  Pursuant to the SOA, we estimate that Vitol held inventories of VGO and crude oil feedstock (both delivered and in-transit) valued at approximately $502.5 million at June 30, 2010 (as compared to $582.1 million at December 31, 2009), which would have otherwise been assets of Harvest.

SUMMARY OF QUARTERLY RESULTS

The following table and discussion highlights our second quarter of 2010 relative to the preceding quarter:

	2010
($000’s)		Q2		Q1
Revenue, net of royalties	$	1,024,896	$	569,762
Net income (loss)		18,203		(39,240	)
Cash from operating activities		122,333		78,134
Total long term debt		1,177,945		1,174,375
Total assets	$	4,758,472	$	4,765,580

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Revenues are comprised of revenues net of royalties from our U pstream operations as well as sales of refined products from our Downstream operations.  First quarter revenues were lower than second quarter revenues primarily due to the fire in the refinery that occurred in early January 2010 that resulted in the shutdown of production units for approximately eight weeks to conduct repairs. Second quarter Downstream revenues were $820.5 million compared to $339.8 million in the first quarter. Upstream revenues in the second quarter were $245.6 million compared to $271.7 million in the first quarter predominantly due to lower commodity prices for oil and natural gas.

Net income reflects both cash and non-cash items. Changes in non-cash items, including future income tax, DDA&A expense, unrealized foreign exchange gains and losses, unrealized gains on risk management contracts and goodwill impairment impact net income from period to period.  For these reasons, our net income (loss) may not necessarily reflect the same trends as net revenues or cash from operating activities, nor is it expected to. Net Income of $18.2 million in the second quarter compared to a net loss of $39.2 million in the first quarter is related to the increase in revenue contributed from our Downstream operations for the reasons as discussed above.

Changes in cash from operating activities are closely aligned with the trend in commodity prices for our Upstream operations, reflects the cyclical nature of the Downstream segment, and is significantly impacted by changes in working capital. During the second quarter cash from Upstream operating activities was lower due to lower commodity prices and the higher operating costs due to the increased cost of electricity. Downstream cash flow from operations increased in the second quarter as the production units resumed operations following the completion of repairs for the January fire.  The first quarter of 2010 was impacted by reductions in refinery throughput resulting from the unplanned downtime as a consequence of the fire in January 2010, partially offset by an increase in realized prices in the Upstream segment.

Total debt and total assets over the two reported quarters have remained relatively stable. The stability in total assets reflects minimal acquisition activity offset by a reduction in net book value associated with depletion and depreciation charges.

OUTLOOK

The evolution of Harvest to a growth oriented, integrated, oil and gas company continued in the second quarter. Harvest has assembled an enviable asset base with growth opportunity that it is looking to complement with additional assets in the years ahead. A strong balance sheet, solid and increasing technical capability, and support for growth from KNOC will position Harvest well.

Subsequent to June 30, 2010, we successfully closed on the acquisition of the BlackGold oil sands project from KNOC for approximately $374 million of equity. We also signed a purchase and sale agreement to purchase certain petroleum and natural gas assets for $150 million. Further details of these subsequent events are discussed in Note 18 of the June 30, 2010 interim financial statements. With the inclusion of these subsequent event acquisitions, we anticipate that our upstream production will average approximately 36,300 bbls/d of liquids and 81,000 mcf/d of natural gas with operating costs approximately $14.00/boe.  Upstream capital spending plans for 2010 are increased to $415 million which includes anticipated spending for the BlackGold project which will be financed through capital injections from KNOC. We will continue to evaluate opportunities to acquire producing oil and/or natural gas properties as well as offer selected properties for divestment to increase or maintain our productive capabilities.

In our downstream business, we currently anticipate spending approximately $120 million on capital projects, including $80 million for the discretionary Debottleneck Projects. The Debottleneck Projects are a suite of investments planned for the next couple years that will increase throughput, improve reliability, enhance margins and reduce operating costs. The shutdown of the platformer, hydrocracking, distillate hydrotreating units previously planned for 2010 have been deferred to 2011, so there will be no turnaround or catalyst expenditures in 2010. 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 $6.25 per bbl.

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Currently the economic environment is mixed for Harvest with strong crude oil and natural gas liquids prices and improving refining margins offset by weaker natural gas prices. 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.

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 six months of the year to changes in the following benchmark prices:

	Assumption		Change		Impact on Cash Flow
WTI oil price (US$/bbl)	$	80.00	$	5.00	$	23 mm
CAD/USD exchange rate	$	0.95	$	0.05	$	26 mm
AECO daily natural gas price	$	4.00	$	1.00	$	13 mm
Refinery crack spread (US$/bbl)	$	9.00	$	1.00	$	21 mm
Upstream operating expenses (per boe)	$	14.00	$	1.00	$	10 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.

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.

Reserves

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

· Expected reservoir characteristics based on geological, geophysical and engineering assessments;

· Future production rates based on historical performance and expected future operating and investment activities;

· Future oil and gas prices and quality differentials; and

· Future development costs.

We follow the full cost method of accounting for our oil and natural gas activities. All costs of acquiring oil and natural gas properties and related exploration and development costs, including overhead charges directly related to these activities, are capitalized and accumulated in one cost centre. Maintenance and repairs are charged against income, and renewals and enhancements that extend the economic life of the capital assets are capitalized. The provision for depletion and depreciation of petroleum and natural gas assets is calculated on the unit-of-production method based on proved reserves as estimated by independent petroleum engineers.

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

Asset Retirement Obligations

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

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Impairment of Capital Assets

Numerous estimates and judgments are involved in determining any potential impairment of capital assets. The most significant assumptions in determining future cash flows are future prices and reserves for our upstream operations and expected future refining margins and capital spending plans for our downstream operations.

The estimates of future prices and refining margins require significant judgments about highly uncertain future events. Historically, oil, natural gas and refined product prices have exhibited significant volatility from time to time. The prices used in carrying out our impairment tests for each operating segment are based on prices derived from a consensus of future price forecasts among industry analysts. Given the number of 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 40%, the initial assessment of impairment of our upstream assets 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.  Similarly, for our downstream operations, if forecast refining margins were to fall by more than 15%, it is likely that our downstream assets would experience an impairment despite the expected seasonal volatility in earnings.

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

Employee Future Benefits

We maintain a defined benefit pension plan for the employees of North Atlantic.  Obligations under employee future benefit plans are recorded net of plan assets where applicable.  An independent actuary determines the costs of our employee future benefit programs using the projected benefit method.  The determination of these costs requires management to estimate or make assumptions regarding the expected plan investment performance, salary escalation, retirement ages of employees, expected health care costs, employee turnover, discount rates and return on plan assets.  The obligation and expense recorded related to our employee future benefit plans could increase or decrease if there were to be a change in these estimates.  Pension expense represented less than 0.5% of our total expenses for the six months ended June 30, 2010.

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 acquisition.  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, refining margins 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.

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RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

In December 2008, the CICA issued section 1582, Business Combinations, replacing Section 1581 of the same name.  The new Section will be effective on January 1, 2011 with prospective application and early adoption allowed.  Under the new guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at their market price at the date of the exchange. Currently the purchase price used is based on the market price of the shares for a reasonable period before and after the date the acquisition is agreed upon and announced. This new guidance generally requires all acquisition costs to be expensed, while the current standard requires capitalization as part of the purchase price. Contingent liabilities are to be recognized at fair value at the acquisition date and remeasured at fair value through earnings each period until settled. While under the current standard only contingent liabilities that are resolved and payable are included in the cost to acquire the business. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from non-current assets in the purchase price allocation.  Harvest is currently assessing the impact of this standard on our financial position and future results.

International Financial Reporting Standards

In February 2008, the CICA Accounting Standards Board (“AcSB”) announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards (“IFRS”) commencing January 1, 2011, including comparatives for 2010 and an opening balance sheet at January 1, 2010 showing the changes from Canadian GAAP to IFRS.

We have established an IFRS Conversion Plan and 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 we meet the IFRS transition requirements for 2011. The IFRS project team has developed an IFRS Transition Plan that consists of four key phases:

IFRS Conversion Project Phase

Phase 1 – Diagnostic Phase

· Assessment of key differences between Canadian GAAP and IFRS, planning, assessment, implementation and training.

Phase 2 – Planning Phase

· Development of a project plan that includes assignment of roles and responsibilities, timeline and budget.

Phase 3 – Assessment Phase

· Detailed comparison of the IFRS and Canadian standards to identify all applicable differences, IFRS 1 First Time Adoption to IFRS exemptions and exemptions and expected changes to the relative IFRS standards.

· Impact assessment on 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.

Phase 4 – Implementation Phase

· Preparing transitional opening IFRS financial statements; implementing accounting policy changes; implementing and test data, process, system and control changes; training

IFRS Project Status

The diagnostic and planning phases of the project have been completed and Harvest has completed the detailed analysis of the differences for most elements of our financial statements and is currently working with representatives from various operational areas in the Company to finalize the selection of accounting policies and assess the impact of the differences on the data requirements, business processes, financial systems and internal controls. Harvest has commenced training of key employees through this process as well. Korea is on the same IFRS conversion schedule as Canada and as a result the IFRS accounting policies that were initially selected were reassessed to ensure that they align with KNOC’s accounting policy choices.

Management is in the process of finalizing its chosen IFRS accounting policies and as such is unable to quantify the impact of adopting IFRS on its financial statements at this time.

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Potential Impacts of IFRS Adoption

Significant differences that have been identified between Canadian GAAP and IFRS that will impact Harvest are: accounting for capital assets including exploration costs, depletion and depreciation, impairment testing, asset retirement obligations, employee benefits as well as an increased level of disclosure requirements. These differences have been identified based on the current IFRS standards issued and expected to be in effect on the date of transition. Current IFRS standards may be modified, and as a result, the impact may be different than Harvest’s current expectations; as such, Harvest cannot guarantee that the following information will not change as the date of transition approaches. Harvest will continue to communicate information in relation to its conversion process as it becomes available.

First Time Adoption of IFRS

IFRS 1, “First Time Adoption of International Financial Reporting Standards” (“IFRS 1”) prescribes requirements for preparing IFRS-compliant financial statements in the first reporting period after the changeover date. IFRS 1 requires retrospective application of IFRS as if they were always in effect. IFRS 1 also provides entities adopting IFRS for the first time with a number of mandatory exceptions and optional exemptions from retrospective application of IFRS to ease the transition to IFRS in the transition year. Management is assessing the exemptions available under IFRS 1 and will implement those determined to be most appropriate for Harvest. At present, Harvest believes it will apply the IFRS 1 exemptions associated with business combinations and arrangements containing a lease.

Property, Plant and Equipment (“PP&E”)

IFRS requires costs recognized as PP&E to be allocated to the significant parts of the asset and to depreciate each significant component separately which is different from Harvest’s current depreciation and depletion calculations under Canadian GAAP. The adoption of IFRS will increase the number of components to be amortized separately for both the upstream and downstream segments which could impact the amount of amortization expense recognized.

Exploration and Evaluation Expenditures (“E&E”)

Oil and gas companies are required to account for exploration and evaluation expenditures in accordance with IFRS 6 “Exploration for and Evaluation of Mineral Resources”. This standard addresses the recognition, measurement, presentation and disclosure requirements for costs incurred in the exploration phase. IFRS requires the identification and presentation of exploration and evaluation (“E&E”) expenditures to be separated from those expenditures incurred on developed and producing properties. E&E expenditures are transferred to PP&E when technical feasibility and commercial viability has been proved. An impairment test is required to be performed on E&E expenditures when they are transferred to PP&E.  Harvest will re-classify all E&E expenditures that are currently included in the PP&E balance and will consist of the book value of E&E land costs, and related drilling costs and seismic costs. E&E assets will not be depleted and will be assessed for impairment when indicators suggest the possibility of impairment.

Impairment of Assets

Under IFRS, impairment of PP&E will be calculated at a more granular level than what is currently required under Canadian GAAP as impairment will be calculated at the cash generating unit level. In addition, IAS 36 “Impairment of Assets” uses a one-step approach for testing and measuring asset impairments, with asset carrying values being compared to the higher of value in use and fair value less costs to sell. Under IAS 36 impairment losses previously recognized may be reversed where circumstances change.

Asset Retirement Obligation (“ARO”)

Under IFRS, the decommissioning liability is required to be remeasured at each reporting date using the current liability specific discount rate requiring retroactive adjustment to the estimated liability, whereas under Canadian GAAP, ARO adjustments are made on a prospective basis.

Employee Benefits

Under IFRS and Canadian GAAP, acturial gains and losses arising from defined benefit plans can be recognized into earnings through various appropriate methods, however, Canadain GAAP does not permit acturial gains and losses to be recognized directly in equity whereas IAS 19 “Employee Benefits” provides an additional accounting policy option to recognize acturial gains and losses directly in other comprehensive income in the period in which they occur.

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Deferred Income Taxes

Due to the recent withdrawal of the exposure draft on IAS 12 “Income Taxes” in November 2009, Harvest is currently evaluating the differences between the current version of IAS 12 and the relevant Canadian GAAP standards.

Internal controls over financial reporting (“ICFR”) and disclosure

As the IFRS accounting policies are finalized, an assessment will be made to determine changes required for ICFR. This will be an ongoing process throughout 2010 to ensure that all changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements. Harvest has established internal controls associated with the IFRS transition which include approvals at various stages of the project and the involvement of its auditors and other external advisors.

Throughout the transition process, Harvest will be assessing stakeholders’ information requirements and will ensure that adequate and timely information is provided so all stakeholders are informed of the transition progress.

IT systems

The conversion to IFRS will have an impact on the company’s IT system requirements. Harvest is currently completing its IT systems impact assessment and it is expected that modifications will include the requirement to track PP&E costs and E&E costs separately as well as the tracking of costs at a more granular level of detail for IFRS reporting. It is expected that current accounting systems and processes will accommodate the modifications required for IFRS reporting.

OPERATIONAL AND OTHER BUSINESS RISKS

Both Harvest’s upstream operations and its downstream operations are conducted in the same business environment as most other operators in the respective businesses and the business risks are very similar.  Harvest has a risk management committee that meets on a regular basis to assesss and manage operational and business risks. We intend to continue executing our business plan to create value.

The following summarizes the more significant risks:

Upstream Operations

· Prices received for petroleum and natural gas have fluctuated widely in recent years and are also impacted by the volatility in the Canadian/US currency exchange rate. The differential between light oil and heavy oil compounds the fluctuations in the benchmark oil prices.

· The operation of petroleum and natural gas properties involves a number of operating and natural hazards which may result in blowouts, environmental damage and other unexpected and/or dangerous conditions.

· The production of petroleum and natural gas may involve a significant use of electrical power and since de-regulation of the electric system in Alberta, electrical power prices in Alberta have been volatile.

· The markets for petroleum and natural gas produced in western Canada depend upon available capacity to refine crude oil and process natural gas as well as pipeline capacity to transport the products to consumers.

· The reservoir and recovery information in reserve reports are estimates and actual production and recovery rates may vary from the estimates and the variations may be significant.

· Absent capital reinvestment, production levels from petroleum and natural gas properties will decline over time and absent commodity price increases, cash generated from operating these assets will also decline.

· Prices paid for acquisitions are based in part on reserve report estimates and the assumptions made preparing the reserve reports are subject to change as well as geological and engineering uncertainty.

· The operation of petroleum and natural gas properties is subject to environmental regulation pursuant to local, provincial and federal legislation and a breach of such legislation may result in the imposition of fines as well as higher operating standards that may increase costs.

Downstream Operations

· The market prices for crude oil and refined products have fluctuated significantly, the direction of the fluctuations may be inversely related and the relative magnitude may be different resulting volatile refining margins.

· The prices for crude oil and refined products are generally based in US dollars while our operating costs are denominated in Canadian dollars which introduces currency exchange rate exposure.

· Crude oil feedstock is delivered to our refinery via waterborne vessels which could experience delays in transporting supplies due to weather, accidents, government regulations or third party actions.

· We are relying on the creditworthiness of Vitol for our purchase of feedstock and should their creditworthiness deteriorate, crude oil suppliers may restrict the sale of crude oil to Vitol.

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· Our refinery is a single train integrated interdependent facility which could experience a major accident, be damaged by severe weather or otherwise be forced to shutdown which may reduce or eliminate our cash flow.

· Our refining operations which include the transportation and storage of a significant amount of crude oil and refined products are adjacent to environmentally sensitive coastal waters, and are subject to hazards and similar risks such as fires, explosions, spills and mechanical failures, any of which may result in personal injury, damage to our property and/or the property of others along with significant other liabilities in connection with a discharge of materials.

· The production of aviation fuels subjects us to liability should contaminants in the fuel result in aircraft engines being damaged and/or aircraft crashes.

· Collective agreements with our employees and the United Steel Workers of America may not prevent a strike or work stoppage and future agreements may result in an increase in operating costs.

· Refinery operations are subject to environmental regulation pursuant to local, provincial and federal legislation and a breach of such legislation may result in the imposition of fines as well as higher operating standards that may increase costs.

General Business Risks

· The loss of a member to our senior management team and/or key technical operations employee could result in a disruption to either our upstream or downstream operations.

· Variations in interest rates on our current and/or future financing arrangements may result in significant increases in our borrowing costs.

· Our crude oil sales and refining margins are denominated in US dollars while we incur costs in Canadian dollars which results in a currency exchange exposure.

· Changes in tax and other laws my affect shareholders. Income tax laws, other laws or government incentive programs relating to the oil and gas industry, may in the future be changed or interpreted in a manner that affects Harvest or its stakeholders.

· Although the Corporation monitors the credit worthiness of third parties it contracts with through a formal risk management policy, there can be no assurance that the Corporation will not experience a loss for non-performance by any counterparty with whom it has a commercial relationship. Such events may result in material adverse consequences on the business of the Corporation.

CHANGES IN REGULATORY ENVIRONMENT

Alberta

On October 25, 2007, the Government of Alberta released its New Royalty Framework (the “NRF”) outlining changes that increase the royalty rates on conventional oil and gas, oil sands and coal bed methane using a price-sensitive and volume-sensitive sliding rate formula for both conventional oil and natural gas.  These proposals were given Royal Assent on December 2, 2008 and became effective January 1, 2009.  Prior to the NRF, the amount of royalties payable was influenced by the oil price, oil production, density of oil and the vintage of the oil with the rate ranging from 10% to 35% and with respect to natural gas production, the royalty reserved was between 15% to 35% depending on the a prescribed or corporate average reference price and subject to various incentive programs.

The NRF sets royalty rates for conventional oil by a single sliding rate formula which is applied monthly and increases the range of royalty rates to up to 50% and with rate caps once the price of conventional oil reaches $120 per barrel.  With respect to natural gas production, the royalties outlined in the NRF are set by a single sliding rate formula ranging from 5% to 50% with a rate cap once the price of natural gas reaches $16.59 per GJ.

The NRF also includes a policy of “shallow rights reversion.”  The shallow rights reversion policy affects all petroleum and natural gas agreements, however, the timing of the reversion will differ depending on whether the leases and licences were acquired prior to or subsequent to January 1, 2009.  Leases granted after January 1, 2009 will be subject to shallow rights reversion at the expiry of the primary term, and in the event of a licence, the policy will apply after the expiry of the intermediate term.  Holders of leases and licences that have been continued indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights which will be implemented three years from the date of the notice.   The lease or licence holder can make a request to extend this period.  The Government intends this policy to maximize the development of currently undeveloped resources by having the mineral rights to shallow gas geological formations that are not being developed revert back to the Government and be made available for resale.

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On April 10, 2008, the Government of Alberta introduced two new royalty programs for the development of deep oil and natural gas reserves.  A five-year oil program for exploratory wells over 2,000 meters will provide royalty adjustments up to $1 million or 12 months of royalty offsets whichever comes first while a natural gas deep drilling program for wells deeper than 2,500 meters will create a sliding scale of royalty credit according to depth of up to $3,750/meter.

On November 19, 2008, the Government of Alberta announced the introduction of a five year program of Transitional Royalty Plan (the “TRP”) which effective January 1, 2009, offers companies drilling new natural gas or conventional deep oil wells (between 1,000 and 3,500 meters) a one-time option, on a well-by-well basis, to reduced royalty rates for new wells for a maximum period of five years to December 31, 2013 after which all wells convert to the NRF.  To qualify for this program, wells must be drilled between November 19, 2008 and December 31, 2013.

On March 3, 2009, the Government of Alberta announced a new three-point stimulus plan, and extended the plan to two years on June 25, 2009.  The drilling royalty credit for new conventional oil and natural gas wells is a two-year program effective for wells spud on or after April 1, 2009, and will provide a $200 per-metre-drilled royalty credit, with the maximum credit determined on a sliding scale based on the individual company’s total Alberta-based 2008 Crown oil and gas production.  The royalty rate cap is also effective April 1, 2009 for new conventional oil and natural gas wells and will provide a maximum 5% royalty rate for the first 12 months of production, to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas per well, to all new wells that begin producing conventional oil or natural gas between April 1, 2009 and March 31, 2011.  The third point is an abandonment and reclamation fund which will provide $30 million to be invested by the Orphan Well Association to abandon and reclaim old well sites where there is no legally responsible or financially able party available.

On May 27, 2010, in connection with its competitiveness review, the Province amended the maximum royalty rates and royalty curves applicable to the New Royalty Framework and amended the new well incentive program that applied to wells commencing production of conventional oil or natural gas on or after April 1, 2009 that was scheduled to expire on March 31, 2011 so that the program was permanent. The incentive provides for a maximum 5% royalty rate for the first 18 to 48 months of production, to a maximum of 50,000 to 100,000 barrels of oil equivalent depending on the depth of the well. The Province will review this program in 2014 and committed to provide three years notice prior to eliminating it.

Saskatchewan

Crown natural gas royalty rates are sensitive to the individual productivity of each well.  The rates are applied to the respective portions of each classification of gas ("fourth tier gas", "third tier gas", "new gas" and "old gas") produced from a well.

Each month, the royalty rates are adjusted based on the level of the Provincial Average Gas Price ("PGP") established by the Province monthly.  The PGP represents the weighted average fieldgate price (expressed in $/103m3) received by producers during the month for the sale of all gas subject to royalty.  Crown royalty of the production volume is calculated on each individual well using the applicable royalty rate to the volume of gas produced by each well on a monthly basis.  The operator must elect to use either the PGP or the Operator Average Gas Price ("OGP") for purposes of valuing the Crown's royalty share of the production volume from each well.  The OGP is determined each month by the operator and represents the weighted average fieldgate price ($/103m3) received by the operator for sales of gas during the month.  The Crown royalty share is calculated by multiplying the Crown royalty volume determined for each well by the wellhead value of the gas for the month.

Crown royalty rates for conventional oil are sensitive to the individual productivity of each well and the type of oil produced from the well.  Each month, royalty rates are adjusted based on the level of the reference price established by the Province for each type of oil.  For Crown royalty purposes, crude oil is classified as "heavy oil", "southwest designed oil" or "non-heavy oil other than southwest designated oil".  There are separate reference prices established for each type of oil which represent the average wellhead price (in $/m3) received by producers during the month for sales of that oil type in Saskatchewan.

The Crown royalty share of production volume is calculated on each individual well using the applicable royalty rate to the volume of oil produced from the well each month.  The Crown royalty share is calculated by multiplying the Crown royalty volume determined for each well by the wellhead value of the oil for the month.  A separate cost sensitive royalty structure applies to incremental production from enhanced oil recovery projects, which incorporates lower royalty and freehold production tax rates before the project reaches payout of investment and operating expenditures.

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Saskatchewan has introduced a new orphan oil and gas well and facility program, solely funded by oil and gas companies to cover the cost of cleaning up abandoned wells and facilities where the owner cannot be located or has gone out of business.  The program is composed of a security deposit, based upon a formula considering assets of the well and the facility licensee against the estimated cost of decommissioning the well and facility once it is no longer producing, and an annual levy assessed to each licensee.

British Columbia

The British Columbia natural gas royalty regime is price-sensitive, using a "select price" as a parameter in the royalty rate formula.  When the reference price, being the greater of the producer price or the Crown set posted minimum price ("PMP"), is below the select price, the royalty rate is fixed.  The rate increases as prices increase above the select price.  The Government of British Columbia determines the producer prices by averaging the actual selling prices for gas sales with shared characteristics for each company minus applicable costs.  If this price is below the PMP, the PMP will be the price of the gas for royalty purposes.

Natural gas is classified as either "conservation gas" or "non-conservation gas".  There are three royalty categories applicable to non-conservation gas, which are dependent on the date on which title was acquired from the Crown and on the date on which the well was drilled.  The base royalty rate for non-conservation gas ranges from 9% to 15%.  A lower base royalty rate of 8% is applied to conservation gas.  However, the royalty rate may be reduced for low productivity wells.

The royalty regime for oil is dependent on age and production.  Oil is classified as "old", "new" or "third tier" and a separate formula is used to determine the royalty rate depending on the classification.  The rates are further varied depending on production.  Lower royalty rates apply to low productivity wells and third tier oil to reflect the increased cost of exploration and extraction.  There is no minimum royalty rate for oil.

In May 2008, the Government of British Columbia introduced the Net Profit Royalty Program to stimulate development of high risk and high cost natural gas and oil resources in British Columbia that are not economic under other royalty programs. The program allows for the calculation of royalties based on the net profits of a particular project and is governed under the Net Profit Royalty Regulation, which came into effect in May 2008.

On August 6, 2009, the Province of British Columbia announced an Oil and Gas Stimulus package providing for:

· A one-year, two per cent royalty rate for all natural gas wells drilled in a 10 month window (September 2009 - June 2010).

· An increase of 15 per cent in the existing royalty deductions for natural gas deep drilling.

· Qualification of horizontal wells drilled between 1,900 and 2,300 metres into the Deep Royalty Credit Program.

An additional $50 million was allocated in the fall of 2009 for the Infrastructure Royalty Credit Program to stimulate investment in oil and gas roads and pipelines.

Environmental Regulation

In 2007, the Government of Alberta introduced the Climate Change and Emissions Management Amendment Act which intends to reduce greenhouse gas emissions intensity from large emitting facilities.  On January 24, 2008, the Government of Alberta announced their plan to reduce projected emissions in the province by 50% under the new climate change plan by 2050.  This will result in real reductions of 14% below 2005 levels.  The Government of Alberta stated they will form a government-industry council to determine a go-forward plan for implementing technologies, which will significantly reduce greenhouse gas emissions by capturing air emissions from industrial sources and locking them permanently underground in deep rock formations.

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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.  On March 10, 2008, the Government of Canada released “Turning the Corner” outlining additional details to implement their April 2007 commitment to cut greenhouse gas emissions by an absolute 20% by 2020.  “Turning the Corner” sets out a framework to establish a market price for carbon emissions and sets up a carbon emission trading market to provide incentives for Canadians to reduce their greenhouse gas emissions.  In addition, the regulations include new measures for oil sands developers that require an 18% reduction from 2006 levels by 2010 for existing operations and for oil sands operations commencing in 2012, a carbon capture and storage capability.  There is no mention of targeting reductions for unintentional fugitive emissions for conventional producers.  Companies will be able to choose the most cost effective way to meet their emissions reduction targets from in-house reductions, contributions to time-limited technology funds, domestic emissions trading and the United Nations’ Clean Development Mechanism.  Companies that have already reduced their greenhouse gas emissions prior to 2006 will have access to a limited one-time credit for early adoption.  Giving the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, and the lack of detail in the Government of Canada’s announcement, it is not possible to assess the impact of the requirements on our operations and financial performance.

DISCLOSURE CONTROLS AND PROCEDURES

As part of the corporate reorganization and dissolution of the Trust on May 1, 2010, the newly reorganized company, Harvest Operations Corp. will continue to assume the disclosure controls and procedures of the Trust. Under the supervision of the Chief Executive Officer and Chief Financial Officer, the Trust had evaluated the effectiveness of its disclosure controls and procedures as of December 31, 2009 as defined under the rules adopted by the Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.  Based on this evaluation, the Chief Executive Officer and Chief Financial Officer had concluded that as of December 31, 2009, the disclosure controls and procedures were effective to ensure that information required to be disclosed by the Trust in reports it files or submits to Canadian and U.S. securities authorities was recorded, processed, summarized and reported within the time period specified in Canadian and U.S. securities laws and was accumulated and communicated to management, including its Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.

During the six months ended June 30, 2010, there were no changes in our disclosure controls and procedures that have materially affected, or are reasonably likely to materially affect, our disclosure controls and procedures.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining internal control over the Company’s financial reporting.  As part of the corporate reorganization and dissolution of the Trust on May 1, 2010, the newly reorganized company, Harvest Operations Corp. will continue to assume the internal controls and processes of the Trust. The Company’s internal controls are designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with Canadian Generally Accepted Accounting Principles.  Management of the Trust, with the participation of its Chief Executive Officer and Chief Financial Officer, had evaluated the effectiveness of its internal control over financial reporting as of December 31, 2009.  The evaluation was based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on that evaluation, management had concluded that as of December 31, 2009, the design and operation of internal controls were effective.

During the six months ended June 30, 2010, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Based on their inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, errors or fraud.  Control systems, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control systems are met.

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ADDITIONAL INFORMATION

Further information about us, 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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