Harvest Energy Trust 6K Harvest Energy Announces Fourth Quarter and Full Year 2007 Results and Distribution Declaration | HTE 14 Mar 08

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s discussion and analysis (“MD&A”) of the financial condition and results of operations of Harvest Energy Trust should be read in conjunction with our audited consolidated financial statements and accompanying notes for the years ended December 31, 2007 and 2006. The information and opinions concerning our future outlook are based on information available at March 12, 2008.

When reviewing our 2007 results and comparing them to 2006, readers should be cognizant that the 2007 results include twelve months of operations from our acquisition of Viking Energy Royalty Trust (“Viking”) in February 2006, Birchill Energy Ltd. (“Birchill”) in August 2006 and North Atlantic Refining Ltd. (“North Atlantic”) in October 2006 and five months from our acquisition of Grand Petroleum Inc. (“Grand”) in August 2007 whereas the comparative results in 2006 include only eleven months of operations from our acquisition of Viking, five months of operations from our acquisition of Birchill and ten weeks of operations from our acquisition of North Atlantic. This significantly impacts the comparability of our operations and financial results for the year ended December 31, 2007 to the comparative period in the prior year.

In this MD&A, reference to “Harvest”, “we”, “us” or “our” refers to Harvest Energy Trust and all of its controlled entities on a consolidated basis. All references are to Canadian dollars unless otherwise indicated. Tabular amounts are in thousands of dollars unless otherwise stated. Natural gas volumes are converted to barrels of oil equivalent (“boe”) using the ratio of six thousand cubic feet (“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: 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, and without including any royalty interests, unless otherwise stated. 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.

In this MD&A, we use certain financial reporting measures that are commonly used as benchmarks within the petroleum and natural gas industry such as Earnings From Operations, Cash General and Administrative Expenses and Operating Netbacks and with respect to the refining industry, Earnings (Loss) from Operations and Gross Margin which are each defined in this MD&A. These measures are not defined under Canadian generally accepted accounting principles (“GAAP”) and should not be considered in isolation or as an alternative to conventional GAAP measures. Certain of these measures are not necessarily comparable to a similarly titled measure of another issuer. When these measures are used, they are defined as “Non-GAAP” and should be given careful consideration by the reader. Please refer to the discussion under the heading “Non-GAAP Measures” at the end of this MD&A for a detailed discussion of these reporting measures.

FORWARD-LOOKING INFORMATION

This MD&A highlights significant business results and statistics from our consolidated financial statements for the year ended December 31, 2007 and the accompanying notes thereto. In the interest of providing our Unitholders and potential investors with information regarding Harvest, including our assessment of our future plans and operations, this MD&A contains forward-looking statements that involve risks and uncertainties. Such risks and uncertainties include, but are not limited to, risks associated with conventional petroleum and natural gas operations; risks associated with refinery operations, the volatility in commodity prices and currency exchange rates; risks associated with realizing the value of acquisitions; general economic, market and business conditions; changes in environmental legislation and regulations; the availability of sufficient capital from internal and external sources and such other risks and uncertainties described from time to time in our regulatory reports and filings made with securities regulators.

Forward-looking statements in this MD&A include, but are not limited to, the several 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, capital taxes, 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.

2007 Financial and Operating Highlights

Cash from operating activities of $641.3 million, representing an increase of $133.4 million over the prior year primarily due to a full year of downstream operations, the realization of $53.6 million of currency exchange gains and a $39.4 million reduction in cash settlements on our crude oil pricing contracts.

Upstream operations contributed $624.3 million of cash reflecting production of 60,336 boe/d with strong commodity prices offset by a strengthening of the Canadian dollar and higher operating costs.

Acquired Grand Petroleum for total cash consideration of $139.3 million representing a cost of approximately $41,000 per flowing barrel and $23.00 per boe for proved and probable reserves complementing our existing oil operations in southeast Saskatchewan.

Capital spending of $300.7 million in our upstream operations plus $138.2 million of net acquisitions replaced 2007 production with finding and development costs, including changes in future development costs, of $28.10 per boe.

Downstream operations contributed $165.0 million of cash in 2007 reflecting refining throughput of 114,646 bbl/d and refining margins of US$13.69 per barrel during the first half of the year with an acceleration of turnaround activities significantly reducing throughput and increasing costs during the second half of 2007.

Increased credit facility to $1.6 billion and extended the maturity date to April 2010 while maintaining the cost of borrowing with a quality syndicate of Canadian and international financial institutions.

Declared distributions totaling $610.3 million ($4.40 per Trust Unit) with 29% participation in our distribution reinvestment programs providing $178.5 million of additional equity.

SELECTED ANNUAL INFORMATION

The table below provides a summary of our financial and operating results for years ended December 31, 2007 and 2006.

	Year Ended December 31

($000s except where noted)
		2007		2006	Change

Revenue, net(1)	4,069,600		1,380,825		195%

Cash From Operating Activities		641,313		507,885	26%
Per Trust Unit, basic	$	4.63	$	5.00	(7%)
Per Trust Unit, diluted	$	4.30	$	4.84	(11%)

Net Income (Loss)(2)	(25,676)			136,046	(119%)
Per Trust Unit, basic	$	(0.19)	$	1.34	(114%)
Per Trust Unit, diluted	$	(0.19)	$	1.33	(114%)

Distributions declared		610,280		468,787	30%
Distributions declared, per Trust Unit	$	4.40	$	4.53	(3%)
Distributions declared as a percentage of Cash From Operating Activities		95%		92%	3%

Bank debt	1,279,501		1,595,663		(20%)
77/8% Senior Notes		241,148		291,350	(17%)
Convertible Debentures(3)		651,768		601,511	8%
Total long-term financial liabilities(3)	2,172,417		2,488,524		(13%)

Total assets	5,451,683		5,745,558		(5%)

UPSTREAM OPERATIONS
Daily Production
Light to medium oil (bbl/d)		27,165		27,482	(1%)
Heavy oil (bbl/d)		14,469		13,904	4%
Natural gas liquids (bbl/d)		2,412		2,247	7%
Natural gas (mcf/d)		97,744		96,578	1%
Total daily sales volumes (boe/d)		60,336		59,729	1%

Operating Netback ($/boe)		29.89		30.54	2%

Cash capital expenditures		300,674		376,881	(20%)

DOWNSTREAM OPERATIONS(4)
Average daily throughput (bbl/d)		98,617		86,890	13%
Aggregate throughput (mbbl)		35,995		6,343	467%

Average Refining Margin (US$/bbl)		10.05		9.32	8%

Cash capital expenditures		44,111		21,411	106%

⁽¹⁾

Revenues are net of royalties.

⁽²⁾

Net Income includes a future income tax expense of $65.8 million (2006 – a recovery of $2.3 million) and unrealized net losses on risk management contracts of $147.8 million (2006 – net gains of $52.2 million) for the year ended December 31, 2007. Please see Notes 16 and 18 to the Consolidated Financial Statements for further information.

⁽³⁾

Includes current portion of Convertible Debentures.

⁽⁴⁾

Downstream operations acquired on October 19, 2006.

REVIEW OF OVERALL PERFORMANCE

Harvest is an integrated energy trust with our petroleum and natural gas business focused on the operations and further development of assets in western Canada (our “upstream operations”) and our refining and marketing business focused on the safe operation of a medium gravity sour crude hydrocracking refinery and a retail and wholesale petroleum marketing business both located in the Province of Newfoundland and Labrador (our “downstream operations”).

During 2007, there were two international trends that have significantly impacted Harvest: the appreciation of the Canadian dollar relative to the US dollar and the disruption of international capital markets due to the sub-prime mortgage crisis in the United States and the asset-backed commercial paper problem in Canada. The strengthening of the Canadian dollar tempered the impact of record setting prices for crude oil and refined products as the currency of these pricing benchmarks is denominated in US dollars. For example, the December 31, 2007 closing West Texas Immediate benchmark price (“WTI”) of US$95.98 and a noonday exchange rate of US$1.0120 per Canadian dollar converts to a CDN$94.84 equivalent. This compares to a year earlier when the WTI price was US$61.05 with an exchange rate of US$0.8581 that converted to a CDN$71.15 equivalent resulting in a 57% year-over-year increase in WTI translating to an increase of only 33% in the Canadian dollar equivalent. The impact of a strengthening Canadian dollar for both our upstream business with $937.0 million of crude oil sales and our downstream business with $430.8 million of refining margin is discussed in their respective sections of this MD&A.

In early July 2007, the extent of the sub-prime lending in the United States and the subsequent asset-backed commercial paper problems in Canada severely impacted the non-investment grade debt markets with a tightening of the availability of credit and a re-pricing of credit. We discuss the ongoing impact of this in the Liquidity and Capital Resources section of this MD&A.

During 2007, cash from operating activities totaled $641.3 million, a $133.4 million improvement as compared to $507.9 million in the prior year. While cash generated from our upstream operations of $624.3 million in 2007 remained relatively stable as compared to $626.2 million in the prior year, the cash generated in our downstream operations of $165.0 million in the current year represents a $129.8 million improvement over the prior year reflecting a full year of operations and robust refining margins in the first half of 2007. The increase in contribution from our downstream operations should be considered in light of a $74.1 million increase in interest costs during 2007 also reflecting a full year of ownership. As the Canadian dollar strengthened during 2007, we converted US$654.7 million of US dollar bank loan borrowings to Canadian dollar borrowings crystallizing $47.1 million of currency exchange gains. Cash settlements for our crude oil price risk management contracts totaled $41.5 million in 2007 reflecting a US$57.18 per barrel price cap with 70% participation above the cap, which is a US$13.38 per barrel higher price cap coupled with a 10% increase in participation above the price cap as compared to 2006. The $39.4 million reduction in crude oil risk management losses in 2007 is a result of the US$13.38 higher price cap more than offsetting the US$6.07 increase in the average WTI benchmark price.

Our upstream operations reflected production of 60,336 boe/d in 2007 as compared to 59,729 boe/d in the prior year with the incremental production in 2007 from our 2006 acquisitions of Viking (one month) and Birchill (seven months) and the acquisition of Grand in mid-2007 along with the results of our 2007 capital spending more than offsetting the natural decline and operating disruptions of 2007. Our production decline in 2007 was higher than expected as the assets acquired in the Birchill acquisition included a number of recently completed wells with higher than expected decline rates and our drilling at Hay River in the winter of 2007 did not produce as anticipated resulting in our focus in this area shifting to a repressurization of the reservoir. In addition, our operating costs increased to $300.9 million, representing a 23% increase in per unit operating costs to $13.66 per boe reflecting an overheated Alberta oilfield services market. While the average WTI benchmark price increased 9%, our average realized price per boe increased 5% reflecting generally higher discounts for heavy oil and a strengthening of the Canadian dollar.

In early August 2007, we completed our acquisition of Grand for aggregate cash consideration of $139.3 million and quickly integrated its operations into our organization limiting transition costs. At the time of its acquisition, Grand’s production averaged approximately 3,400 boe/d comprised of approximately 68% oil and 32% natural gas resulting in the acquisition cost being approximately $41,000 per flowing barrel. In addition, the Grand assets included 46,000 net acres of undeveloped land with supporting seismic. Grand’s principal oil producing assets are located in southeast Saskatchewan adjacent to our Hazelwood property with our combined production in this area totaling approximately 3,600 boe/d at year end. In 2008, we are planning to drill 40 wells in southeast Saskatchewan.

Reserve additions in our upstream operations more than replaced our production during 2007 with our proved plus probable reserves at December 31, 2007 totaling 220.9 million boe as compared to 219.9 million boe at the end of 2006. Including changes in future development costs, our 2007 finding and development costs averaged $28.10 per boe while our finding, development and acquisition costs averaged $22.97 per boe as compared to $26.04 per boe and $24.59 per boe, respectively, in the prior year. Included in the 2007 proved plus probable reserve additions are 14.0 million boe attributed to our 2007 capital program and enhanced recovery plans and a further 9.3 million boe for new proved undeveloped reserves which, when coupled with the 10.3 million boe acquired during the year, more than offsets our 2007 production and revisions for underperforming properties. Relative to our 2007 netback price of $29.89, our finding and development costs represent a recycle ratio of 1.06 while our finding, development and acquisition costs represent a recycle ratio of 1.30.

During 2007, our downstream operations generated $165.0 million of cash with $233.1 million generated in the first six months offset by a $68.1 million cash consumption in the last six months. During the first half of 2007, throughput averaged 114,646 bbl/d with our refining margin averaging US$13.69 per barrel which exceeded our expectations. In the second half of the year, our results reflect a significantly reduced refining margin of US$4.16 and the impact of two planned shutdowns. With reduced refining margins appearing early in the third quarter, we accelerated our first shutdown by a few weeks to enable the acceleration of a second shutdown from the spring of 2008, as originally planned, to the fourth quarter of 2007. This acceleration of planned shutdowns better positions us to benefit from anticipated higher refining margins in 2008.

In February 2007, we raised $357.4 million of net proceeds with the issuance of $230 million of principal amount Convertible Debentures and 6,146,750 Trust Units with $289.7 million of proceeds directed to the repayment of our Senior Secured Bridge Credit Facility and the balance applied to our Three Year Extendible Revolving Credit Facility. In April 2007, we increased our Three Year Extendible Revolving Credit Facility from $1.4 billion to $1.6 billion and by October, extended the maturity date of this facility from March 2009 to April 2010 and maintained our syndicate of quality lenders as well as the cost of our borrowing. As the disruptions in the capital markets continue, we are comfortable with the April 2010 maturity date for our credit facilities and may elect to defer further extending the maturity date until capital market conditions improve.

In 2007, we declared distributions to Unitholders totaling $610.3 million ($4.40 per Trust Unit) comprised of ten monthly distributions of $0.38 per Trust Unit and distributions for November and December of $0.30 per Trust Unit. We had maintained our $0.38 per Trust Unit monthly distribution since February 2006 and in light of the impact of a significant strengthening of the Canadian dollar on our crude oil sales revenue and refining margins and the continued high cost of operating in Alberta, we reduced our monthly distribution to $0.30 per Trust Unit effective November 2007 to better balance our cash from operating activities, distributions and capital spending. Unitholder participation in our distribution reinvestment programs generated $178.5 million of equity capital reflecting a 29% average level of participation.

Business Segments

Following our acquisition of North Atlantic in October of 2006, our business has two segments: the upstream operations in western Canada and the downstream operations in the Province of Newfoundland and Labrador. The following table presents selected financial information for our two business segments:

	Year Ended December 31

		2007			2006

(in $000’s)	Upstream	Downstream	Total	Upstream	Downstream	Total
Revenue⁽¹⁾	971,044	3,098,556	4,069,600	920,466	460,359	1,380,825
Earnings From Operations⁽²⁾	169,423	92,270	261,693	211,418	19,740	231,158
Capital expenditures	300,674	44,111	344,785	376,881	21,411	398,292
Total assets	3,968,779	1,482,903	5,451,683	4,017,761	1,727,797	5,745,558

⁽¹⁾

Revenues are net of royalties.

⁽²⁾

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

⁽³⁾

2006 downstream operations are for the period October 19, 2006 to December 31, 2006.

Our Upstream and Downstream operations are each discussed separately in the sections that follow. Additionally, we have included a section entitled ‘Risk Management, Financing and Other’ that discusses, among other things, our cash flow risk management program and related effects on unitholder distributions.

UPSTREAM OPERATIONS

Financial and Operating Results

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

The following summarizes the financial and operating information of our upstream operations for the years ended December 31, 2007 and 2006:

	Year Ended December 31
(in $000’s)	2007	2006	Change

Revenues	$ 1,184,457	$ 1,120,575	6%
Royalties	(213,413)	(200,109)	7%
Net revenues	971,044	920,466	5%

Operating expenses	300,918	242,474	24%
General and administrative	34,615	28,372	22%
Transportation and marketing	11,946	12,142	(2%)
Transaction costs	-	12,072	n/a
Depreciation, depletion, amortization and accretion	454,142	413,988	10%

Earnings From Operations⁽¹⁾	169,423	211,418	(20%)

Cash capital expenditures (excluding acquisitions)	300,674	376,881	(20%)
Property and business acquisitions, net of dispositions	138,158	2,467,097	(94%)

Daily sales volumes
Light to medium oil (bbl/d)	27,165	27,482	(1%)
Heavy oil (bbl/d)	14,469	13,904	4%
Natural gas liquids (bbl/d)	2,412	2,247	7%
Natural gas (mcf/d)	97,744	96,578	1%
Total (boe/d)	60,336	59,729	1%

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

Commodity Price Environment

	Year Ended December 31
Benchmarks	2007	2006	Change

West Texas Intermediate crude oil (US$ per barrel)	72.31	66.24	9%
Edmonton light crude oil ($ per barrel)	76.25	72.79	5%
Bow River blend crude oil ($ per barrel)	63.36	51.04	5%
AECO natural gas daily ($ per mcf)	6.45	6.53	(1%)
AECO natural gas monthly ($ per mcf)	6.61	6.98	(5%)
Canadian / U.S. dollar exchange rate	0.935	0.882	6%

In general, the average West Texas Intermediate (“WTI”) crude oil price has increased steadily throughout 2007, beginning the year at US$54.35/bbl in January and exiting the year with a December average price of US$91.74/bbl, resulting in a 2007 annual average price of $72.31/bbl, a 9% increase over the prior year. The average Edmonton light crude oil price (“Edmonton Par”) also increased steadily throughout 2007, however to a lesser extent than WTI due to the relative strengthening of the Canadian dollar. The Canadian dollar equivalent of WTI for the year ended December 31, 2007 of $77.34 would have been $81.98 (or $4.64 higher) had the Canadian/U.S. dollar exchange rate remained unchanged from the prior year.

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. Throughout 2007, heavy oil demand was impacted by planned maintenance shutdowns and unplanned disruptions of heavy oil refineries in the United States as well as production from new oil sands projects, resulting in widening differentials. Heavy oil differentials for the last eight quarters are shown below.

	2007				2006
Differential Benchmarks	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Bow River Blend differential to Edmonton Par	34.2%	30.0%	29.4%	25.4%	30.3%	25.8%	22.9%	42.0%

North American natural gas storage inventories throughout 2007 were higher than in prior years, and as a result the benchmark natural gas price fell by 5% compared to the prior year to an average of $6.61/mcf from $6.98/mcf in 2006.

Realized Commodity Prices

The following table provides our average realized price by product for 2007 and 2006.

	Year Ended December 31
	2007	2006	Change
Light to medium oil ($/bbl)	64.09	59.82	7%
Heavy oil ($/bbl)	46.71	46.14	1%
Natural gas liquids ($/bbl)	62.26	58.54	6%
Natural gas ($/mcf)	6.94	6.76	3%
Average realized price ($/boe)	53.78	51.40	5%

In 2007 our average realized price was 5% higher than in the prior year, with every product realizing a higher average price than the prior year.

Our realized price for light to medium oil sales increased 7% in 2007 compared to the prior year, reflecting the 5% increase in Edmonton Par pricing over 2006 coupled with improved quality differentials realized on our light to medium oil production relative to the Edmonton Par price during 2007.

Harvest’s heavy oil prices were relatively unchanged in 2007 from 2006, despite a 5% year-over-year increase in the Bow River price. This is a result of the relatively heavier gravity production from our two heavy oil acquisitions completed in December 2006 and March 2007.

The average realized price for our natural gas production was 3% higher in 2007 than in 2006 compared to reductions of 1% in AECO daily pricing and 5% in AECO monthly pricing over the same period. The increase in our realized natural gas prices relative to 2006 is a result of consolidating our gas marketing arrangements with one third party marketer in late 2006. Throughout 2007 we sold approximately 60% of our natural gas off the AECO daily benchmark and approximately 30% off the AECO monthly benchmark with the remainder sold to aggregators. Additionally, our larger natural gas producing properties generally have a higher than average heat content, which realizes a premium in its pricing.

Sales Volumes
The average daily sales volumes by product were as follows:

	Year Ended December 31
	2007		2006
	Volume	Weighting	Volume	Weighting	% Volume Change
Light to medium oil (bbl/d)⁽¹⁾	27,165	45%	27,482	46%	(1%)
Heavy oil (bbl/d)	14,469	24%	13,904	23%	4%
Natural gas liquids (bbl/d)	2,412	4%	2,247	4%	7%
Total liquids (bbl/d)	44,046	73%	43,633	73%	1%
Natural gas (mcf/d)	97,744	27%	96,578	27%	1%
Total oil equivalent (boe/d)	60,336	100%	59,729	100%	1%

⁽¹⁾

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

In 2007, our light/medium oil production has trended downward each quarter, except for the second quarter, resulting in an annual average production level of 27,165 bbl/d which is 317 bbl/d or 1% lower than the average in the prior year. In the first quarter, production was disrupted with a major drilling program at Hay River that produces about 15-20% of our total light/medium oil production. In the second quarter, Hay River production resumed, adding an incremental 1,200 bbl/d of initial production from the new wells. In the third quarter, however, steeper than expected declines were experienced in this property, reducing production by 1,750 bbl/d for the quarter which was partially offset by our August 1, 2007 acquisition of Grand that added approximately 1,100 bbl/d of production. In the fourth quarter, production declined a further 500 bbl/d due to continued declines in Hay River as well as normal declines and power outages at our Hazelwood properties in southeast Saskatchewan and the disposals of some minor properties.

Our heavy oil production increased by 4% in 2007 over 2006 with an average of 14,469 bbl/day. Despite this overall increase, our heavy oil production has actually been decreasing each quarter in 2007. Two heavy oil acquisitions, one in late 2006 and one in March 2007 added approximately 1,055 incremental barrels per day of production for the first quarter, offsetting natural declines in other properties and production disruptions associated with “military lockouts” at our Suffield property where our operations are located on a Canadian Forces military base. In the second quarter, our production was 14,719 bbl/d, an 895 bbl/d reduction from the first quarter due to wet spring conditions with soft roads limiting the movement of well servicing equipment and again, the military lockouts at Suffield. Production volumes declined further in the third and fourth quarters as a result of increased water cuts on various large producing wells in the west central Saskatchewan and Lloydminster areas as well as well servicing activities and normal declines.

Our 2007 natural gas production was relatively unchanged from the prior year, averaging 97,744 mcf/d. Our 2006 acquisitions of Birchill and Viking added incremental gas production with our fourth quarter 2006 production volume totaling 112,006 mcf/d. In 2007 we acquired approximately 7,000 mcf/d additional gas production with Grand in the third quarter and focused our capital program on the tie-in of wells drilled in 2006 and expected a downward trend in our natural gas production. While we experienced higher than expected production declines on a few of the Birchill properties acquired in the prior year, our second and third quarter natural gas production was lower due to various third party processing facility turnarounds, specifically in the Crossfield area where quarterly production volumes were reduced by 1,600 mcf/d.

Revenues

	Year Ended December 31

(000s)		2007		2006	Change
Light to medium oil sales	$	635,470	$	600,061	6%
Heavy oil sales		246,674		234,144	5%
Natural gas sales		247,499		238,367	4%
Natural gas liquids sales and other		54,808		48,003	14%
Total sales revenue		1,184,451		1,120,575	6%
Royalties		(213,413)		(200,109)	7%
Net Revenues	$	971,038	$	920,466	5%

Our revenue is impacted by changes to production volumes, commodity prices, and currency exchange rates. Our 2007 total sales revenue of $1,184.5 million is $63.9 million higher than the prior year, of which $54.9 million is attributed to higher realized prices and $9.0 million in attributed to increased production volumes. The price increase reflects the 5% increase in Edmonton Par pricing in 2007 as compared to 2006, while our increased production volume is mainly attributed to the acquisitions that we have completed in late 2006 and throughout 2007 coupled with our 2007 capital spending program.

Light to medium oil sales revenue for 2007 was $35.4 million higher than in the comparative period, due to a $42.3 million favourable price variance offset by a $6.9 million unfavourable volume variance. Increased demand for Canadian light sweet crude oil has resulted in increased realized prices on our light to medium oil production and has had a positive impact on overall revenue while higher than expected decline rates in Hay River and delayed well servicing activity have contributed to an unfavourable volume variance between 2007 and 2006.

Our 2007 heavy oil sales revenue of $246.7 million was $12.5 million higher than in the prior year due to a $9.5 million favourable volume variance resulting from our acquisitions of heavy oil properties and the incremental production from our drilling program and a $3.0 million favourable price variance reflecting the 5% year-over-year increase in Bow River benchmark pricing.

Natural gas sales revenue increased by $9.1 million in 2007 compared to 2006 due to a $6.2 million favourable price variance coupled with a $2.9 million favourable volume variance. The favourable price variance reflects the $0.18/mcf increase in our realized natural gas prices resulting from our consolidation of gas marketing arrangements to a single third party marketer and the favourable volume variance is primarily attributed to the incremental gas production from the acquisition of Birchill in August 2006 and Grand in August 2007.

During 2007, our natural gas liquids and other sales revenue increased by $6.8 million compared to the prior year, attributed to a $3.5 million favourable volume variance and a $3.3 million favourable price variance. Generally, the natural gas liquids volume variance will be aligned with our production of natural gas while the price variances will be aligned with the prices realized for our oil production.

Royalties

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

Throughout 2007 our net royalties as a percentage of gross revenue were 18.0% (17.9% in 2006) and aggregated to $213.4 million ($200.1 million in 2006). Our 2007 royalty rate is in line with expectations with additional crown royalties assessed on our Hay River properties in 2007, offset by reduced royalties due to increased gas cost allowance credits and crown royalty refunds on some of our shut-in gas-over-bitumen production. See the ”Changes in Regulatory Environment” section in this MD&A for further discussion on Alberta’s New Royalty Framework.

Operating Expenses

	Year Ended December 31
									Per BOE
(000s except per boe amounts)		2007	Per BOE			2006	Per BOE		Change
Operating expense
Power	$	56,427	$	2.56	$	61,056	$	2.80	(9%)
Workovers		60,000		2.72		51,151		2.34	16%
Repairs and maintenance		62,260		2.83		38,969		1.79	58%
Labour – internal		13,887		0.63		20,719		0.95	(31%)
Processing fees		28,764		1.31		15,311		0.70	84%
Fuel		8,725		0.40		7,442		0.34	6%
Labour – external		15,641		0.71		13,012		0.60	18%
Land leases and property tax		21,262		0.97		19,319		0.89	9%
Other		33,952		1.53		15,495		0.71	115%
Total operating expense		300,918		13.66		242,474		11.12	23%

Transportation and marketing expense	$	11,946	$	0.54	$	12,142	$	0.56	(4%)

Our 2007 operating costs totaled $300.9 million as compared to the $242.5 million incurred in 2006. On a per barrel basis, our operating costs have increased to $13.66 in 2007 compared to $11.12 in 2006, representing a 23% increase over the prior year. The largest components of operating expense are workovers and repairs and maintenance costs, and these costs reflect the continued high demand for oilfield services that we experienced throughout the year, resulting in increased overall costs. Additionally, in the third quarter, an extended turnaround at a third-party processing plant in the Crossfield area accounted for a one-time $5.5 million increase in repairs and maintenance expense. The increase in processing fees are directly related to a greater proportion of non-operated properties as a result of our acquisition of Birchill. Generally, we incur higher processing fees on non-operated properties as we own an interest in the well, but may not own an interest in the processing plant and are usually charged a fee for processing which is higher than the per unit cost of operating the facility.

Our 2007 transportation and marketing expense was $11.9 million or $0.54 per boe and is relatively unchanged from $12.1 million or $0.56 per boe in 2006. These costs relate primarily to delivery of natural gas to Alberta’s natural gas sales hub, the AECO Storage Hub, and to a lesser extent, our costs of trucking clean crude oil to pipeline receipt points. As a result, the total dollar amount of costs fluctuate in relation with our natural gas production volumes and the cost per boe is expected to remain relatively constant.

Electric power costs represented approximately 19% of our total operating costs during 2007. Electric power prices of $66.84/MWh in 2007 were 17% lower than the 2006 average of $80.48/MWh and Harvest recognized a $0.24 per boe reduction in power costs before gains on price risk management contracts as a result of this rate reduction. However,

increased power consumption resulting from our acquisition of Birchill in August 2006 and our acquisition of Grand in August 2007 offset the full benefit of the reduction in price. In 2007, our electric power price risk management contracts resulted in a gain of $3.1 million compared to a gain of $11.6 million in the prior year which would be expected with lower power prices. The following table details the electric power costs per boe before and after the impact of our price risk management program.

	Year Ended December 31
(per boe)		2007		2006	Change
Electric power costs	$	2.56	$	2.80	(9%)
Realized gains on electricity risk management contracts		(0.14)		(0.53)	(74%)
Net electric power costs	$	2.42	$	2.27	7%
Alberta Power Pool electricity price (per MWh)	$	66.84	$	80.48	(17%)

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

Operating Netback

	Year Ended December 31
(per boe)		2007		2006
Revenues	$	53.78	$	51.40
Royalties		(9.69)		(9.18)
Operating expense		(13.66)		(11.12)
Transportation and marketing expense		(0.54)		(0.56)
Operating netback⁽¹⁾	$	29.89	$	30.54
⁽¹⁾These are non-GAAP measures; please refer to “Non-GAAP Measures” in this MD&A.

General and Administrative (“G&A”) Expense

	Year Ended December 31

(000s except per boe)		2007		2006	Change
Cash G&A⁽¹⁾	$	31,892	$	27,485	16%
Unit based compensation expense		2,723		887	207%
Total G&A	$	34,615	$	28,372	22%

Cash G&A per boe ($/boe)	$	1.45		1.26	15%

Transaction costs
Unit based compensation expense		-		8,974	n/a
Severance and other		-		3,098	n/a
Total Transaction costs	$	-	$	12,072	n/a

⁽¹⁾

Cash G&A excludes the impact of our unit based compensation expense and for 2006, $12.1 million of one time transaction costs.

For the year ended December 31, 2007, Cash G&A costs increased by $4.4 million (or 16%) compared to the same period in 2006. This increase is mainly related to salaries, which is attributed largely to increased staffing levels from our acquisition of Birchill in August 2006, with a nominal increase associated with our acquisition of Grand. Approximately 75% of our Cash G&A expenses are related to salaries and other employee related costs. Generally, the market for technically qualified staff in the western Canadian petroleum and natural gas industry continues to be tight.

Our unit based compensation plans provide the employee with the option of settling outstanding awards with cash. As a result, our unit based compensation expense is determined using the intrinsic method, being the difference between the Trust Unit trading price and the strike price of the unit awards adjusted for the proportion that is vested. Our Trust Unit market price was $26.15 at January 1, 2007 and on December 31, 2007, our Trust Unit price was $20.63. This reduction in unit value was offset by an increasing number of outstanding awards becoming vested resulting in our 2007 unit based compensation expense of $2.7 million, including a $7.7 million recovery in the last six months of the year as our Trust Unit price decreased from $32.95 at June 30, 2007. Total unit based compensation expense increased $1.8 million in 2007 compared to 2006 due to the increased number of awards granted in 2007 and a large recovery recorded in 2006 resulting from the changes in unit price. In 2006, we recorded transaction costs of $12.1 million which represent one time costs incurred by Harvest as part of the acquisition of Viking in respect of Harvest’s outstanding UARs vesting on February 3, 2006 and severance payments made to Harvest employees upon merging with Viking.

Depletion, Depreciation, Amortization and Accretion Expense
	Year Ended December 31
(000s except per boe)		2007		2006	Change
Depletion, depreciation and amortization	$	420,184	$	381,085	10%
Depletion of capitalized asset retirement costs		15,621		16,950	(8%)
Accretion on asset retirement obligation		18,337		15,953	15%
Total depletion, depreciation, amortization and accretion	$	454,142	$	413,988	10%
Per boe	$	20.62	$	18.99	9%

Our overall depletion, depreciation, amortization and accretion (“DDA&A”) expense for the year ended December 31, 2007 was $40.2 million higher than the prior year. The increased expense reflects increased production volumes resulting from our acquisitions coupled with higher finding and development costs that have increased our DDA&A rate.

Capital Expenditures
	Year Ended December 31
(000s)		2007		2006
Land and undeveloped lease rentals	$	2,785	$	9,756
Geological and geophysical		6,058		6,709
Drilling and completion		146,941		214,964
Well equipment, pipelines and facilities		134,423		125,444
Capitalized G&A expenses		8,353		13,141
Furniture, leaseholds and office equipment		2,114		6,867
Development capital expenditures excluding acquisitions and non-cash items		300,674		376,881
Non-cash capital additions (recoveries)		371		(533)
Total development capital expenditures excluding acquisitions	$	301,045	$	376,348

In 2007, Harvest invested $300.7 million in development capital expenditures compared to $376.9 million in 2006. Approximately 49% of these expenditures were costs to drill 182 gross wells with a success rate of 98%, compared to 252 gross wells with a success rate of 98% in 2006. While we continued to focus our drilling activity on oil opportunities (74% of the total net wells drilled) given the strong oil price environment, our central Alberta gas drilling resulted in some particularly successful wells. At Cheddarville, we drilled an Ostracod seismic anomally and discovered a large hydrocarbon charged porous interval. The well was tied-in late in 2007 and has been producing approximately 700 boe/d of sweet natural gas and associated liquids. A second well at Markerville targeting the Ellerslie formation was found to have a productive capacity in the order of 500 boe/d

Over 70% of our net drilling activity throughout the year took place in the five major areas of Hay River, southeast Saskatchewan, Lloydminster, Suffield and Red Earth. In Hay River we drilled 31 wells and in 2008, we are focusing on additional water injection required to re-pressurize the reservoir. At Southeast Saskatchewan, a significant new light oil pool was discovered at Kenosee in 2006 and we drilled 13 gross horizontal wells to begin its exploitation, resulting in production in excess of 600 boe/d by the end of the year. Also at southeast Saskatchewan we drilled a further 20 horizontal wells pursuing light oil accumulations in both the Souris Valley and Tilston formations with a 100% success rate. At Lloydminster and Suffield, we drilled 15 and 11 gross horizontal wells, respectively, accessing heavy oil from the Lloydminster and Glauconitic sandstone formations. At Red Earth, we continued to pursue light oil opportunities in the Slave Point, Granite Wash, and Gillwood formations with a total of 12 gross wells drilled. In addition to our drilling activity we shot a large 3D seismic program on prospective lands acquired in 2006, and we added to our oilsands land inventory with the acquisition of 11,400 net acres bringing our total oilsands rights in the Red Earth area to 29,000 net acres. At Markerville, we drilled 22 gross wells pursuing shallow gas opportunities in the Edmonton Sands formation and liquids rich sweet natural gas in the Pekisko formation.

Our enhanced recovery projects continued to progress in 2007 as we plan the implementation phase for 2008. At Bellshill Lake, we have confirmed through an independent engineering study as well as field trials that increased water injection will translate to a reduction in our current decline rate and result in an improved recovery from this large medium gravity oil pool. At Wainwright, we completed the majority of our laboratory testing and are in the final stages of equipment selection to begin construction on our ASP (Alkaline Surfactant Polymer) flood pilot that could access incremental medium oil if implemented field wide. A pilot will test this technology on an area representing approximately 10% of the pool starting in the 4th quarter of 2008. At Suffield, in 2008 we will launch an enhanced waterflood to increase the volume of water injection with expectation of a reduction in decline rates as well as an increase in recoverable reserves.

The $134.4 million of well equipment, pipelines and facilities expenditures during 2007 include a number of initiatives to improve the efficiency of our Hay River operations including the construction of an all season access road, the installation of natural gas infrastructure to eliminate flaring of produced natural gas, an electrical distribution system as well as well equipment required to bring new wells into production. Various other initiatives have been undertaken to improve overall efficiency in other areas, including an expansion of our oil processing facilities at Red Earth intended to optimize Slave Point light oil production and to provide the necessary infrastructure to accommodate our 2008 drilling program. An emulsion processing facility at Kenosee in southeast Saskatchewan has been constructed, also to accommodate the incremental production from our 2008 drilling program. Replacement of pipelines at Kilarney, Hayter and Bashaw are included as part of Harvest’s capital maintenance program to maintain the integrity of our producing infrastructure.

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

	Total Wells		Successful Wells		Abandoned Wells
Area	Gross⁽¹⁾	Net	Gross	Net	Gross	Net

Hay River	31.0	31.0	31.0	31.0	-	-
Southeast Saskatchewan	33.0	29.0	33.0	29.0	-	-
Markerville	22.0	9.6	22.0	9.6	-	-
Lloydminster	15.0	15.0	15.0	15.0	-	-
Red Earth	12.0	8.5	12.0	8.5	-	-
Suffield	11.0	11.0	9.0	9.0	2.0	2.0
Hayter	7.0	5.3	7.0	5.3	-	-
Other Areas	51.0	22.2	49.0	21.6	2.0	0.6
Total	182.0	131.6	178.0	129.0	4.0	2.6

⁽¹⁾ Excludes 31 additional wells that we have an overriding royalty interest in.

Our 2007 capital program, along with our acquisitions and divestitures, more than replaced our production on a proved plus probable basis with 2007 year end reserves of 220.9 million boe, essentially unchanged from 219.9 million boe at the end of 2006. Including changes in future development costs, our 2007 finding and development cost averaged $28.10 per boe while our finding, development and acquisition costs averaged $22.97 per boe as compared to $26.04 per boe and $24.59 per boe, respectively, in the prior year. Based on the forecast prices and costs of our independent reservoir engineers as at December 31, 2007, the net present value of our future net revenues from proved reserves using a 10% discount rate is $2,865.8 million and $3,675.1 million from proved plus probable reserves. Relative to our 2007 netback price of $29.89/boe, our finding and development costs result in a recycle ratio of 1.06 while our finding, development and acquisition costs result in a recycle ratio of 1.30. Based on our 2007 production of 22.0 million boe, our 2007 year end proved reserves represent a reserve life index of 7 years while our proved plus probable reserves represent a reserve life index of 10 years.

Corporate Acquisitions

Effective March 1, 2007, we acquired a private petroleum and natural gas corporation for cash consideration of $30.6 million which added approximately 1,500 bbl/d of western Saskatchewan heavy oil production which is adjacent to our existing operations in the area.

In early August 2007, we completed the acquisition of Grand for aggregate consideration of approximately $139.3 million, acquiring approximately 3,400 boe/d of production with proved plus probable (P+P) reserves of 6 million boe, composed of approximately 67% oil. The Grand assets include a significant presence in southeast Saskatchewan, the Sylvan Lake/Markerville area and eastern Alberta which are adjacent to existing Harvest operations with complementary drilling opportunities. We also acquired 65,000 acres (46,000 net acres) of undeveloped land with supporting seismic data providing further development opportunities. This acquisition represents an acquisition cost of approximately $41,000 per flowing boe and $23.00 per boe of proved and probable reserves.

Goodwill

Goodwill is recorded when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of that acquired business. At December 31, 2006, we had recorded $656.2 million of goodwill related to our upstream segment and during 2007 we added an additional $20.5 million of goodwill with our purchase of Grand. The goodwill balance is assessed annually for impairment or more frequently if events or changes in circumstances occur that would reasonably be expected to reduce the fair value of the acquired business to a level below its carrying amount. To date, no charge for impairment of this goodwill has been made.

Asset Retirement Obligation (“ARO”)

In connection with property acquisitions and development expenditures, we record the fair value of the ARO as a liability in the same year as the expenditure occurs. 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 $11.0 million during the year ended December 31, 2007. The increase is a result of additional obligations incurred through our corporate acquisitions and drilling activity throughout the year as well as accretion expense, offset by $13.1 million of actual asset retirement expenditures incurred.

DOWNSTREAM OPERATIONS

Our downstream operations, operating under the North Atlantic trade name, are comprised of a medium gravity sour crude hydrocracking refinery with a 115,000 bbl/d nameplate capacity and a marketing division with 64 gasoline outlets, a home fuel business and a commercial and wholesale petroleum products business, all located in the Province of Newfoundland and Labrador. The sales volume of our marketing division represents approximately 20% of the Newfoundland market.

Since the acquisition of North Atlantic, our quarter-over-quarter operating results of our downstream business have not been very comparable due to planned shutdowns for refinery turnaround activities and the seasonal demand for refined products affecting throughput volumes and the volatility of refining margins, respectively. For the period ending December 31, 2006, our results reflect the impact of an extended turnaround commencing October 1, 2006 with the refinery returning to full operations near the end of November 2006 only to experience additional downtime in December 2006 due to a pipe rupture and a disruption in electric power service. Our operations for the first six months ended June 30, 2007 reflect solid operating performance with throughput of 114,646 bbl/d and robust refining margins generating $232.1 million of cash while the performance for the next six months reflect the impact of two planned shutdowns and substantially weaker refining margins. Accordingly, the analysis of our downstream operations will not be a comparison of one operating period with another but rather a review of the activities for each period and their impact on operating results.

The following summarizes our downstream financial and operational results for 2007 and 2006:

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

Revenues	1,684,432	1,414,124	3,098,556	460,359
Purchased feedstock for processing and products
purchased for resale	1,340,938	1,326,776	2,667,714	386,014
Gross Margin⁽¹⁾	343,494	87,348	430,842	74,345

Costs and expenses
Operating expense	51,945	50,531	102,476	18,378
Purchased energy expense	42,337	49,991	92,328	15,685
Turnaround and catalyst expense	-	34,486	34,486	-
Marketing expense	16,402	18,568	34,970	5,060
General and Administrative	702	1,011	1,713	-
Depreciation and amortization expense	37,574	35,026	72,600	15,482
Earnings (loss) from operations⁽¹⁾	194,534	(102,265)	92,269	19,740

Cash capital expenditures	14,754	29,357	44,111	21,411

Feedstock volume (bbl/day)⁽²⁾	114,646	82,849	98,617	86,890

Yield (000’s barrels)
Gasoline and related products	6,689	4,826	11,515	1,875
Ultra low sulphur diesel and jet fuel	8,233	6,173	14,406	2,624
High sulphur fuel oil	5,695	4,148	9,843	1,752
Total	20,617	15,147	35,764	6,251

Average Refining Margin (US$bbl)⁽³⁾	13.69	4.16	10.05	9.32

⁽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 margin is calculated based on per barrel of throughput

Overview of Downstream Financial Performance

During 2007, our downstream operations generated $165.0 million of cash with $233.1 million generated in the first six months offset by a $68.1 million cash deficiency in the last six months of the year. Earnings from operations of $92.3 million for 2007 is comprised of earnings of $194.5 during the first six months and a loss of $102.3 million during the last six months. Our results for the first six months of 2007 reflect solid operating performance with throughput of 114,646 bbl/d and unit operating costs (operating expenses plus the cost of purchased energy) averaging $4.12 per barrel with an average refining margin of US$13.69 per barrel. During the first half of 2007, the sale of our refined products increased from US$71.03 per barrel to US$94.90 for gasoline and from US$74.18 per barrel to US$85.43 for distillate from the first quarter to second quarter, respectively, while the cost of our feedstock (crude oil and vacuum gas oil) increased from US$51.73 per barrel in the first quarter to US$60.46 in the second quarter resulting in robust refining margins during the first six months of 2007.

Our downstream operations during the last six months of 2007 reflect significantly reduced refining margins and two planned shutdowns. During the third quarter of 2007, increases in the cost of our crude oil feedstock were not accompanied with higher gasoline and distillate prices resulting in the significant erosion of our refining margin from US$15.64 per barrel of throughput in the second quarter to US$3.08 in the third quarter. Anticipating that refining margins were more likely to improve in the first half of 2008 than in the fourth quarter of 2007, we accelerated our first shutdown by a few weeks to enable the acceleration of a second shutdown from the spring of 2008, as originally planned, to the fourth quarter of 2007. During the first shutdown in September, we replaced and regenerated the catalyst in the Isomax and Platformer units, respectively, as well as completed routine inspection and maintenance on these units. Subsequent to the re-commissioning of the Isomax and Platformer units in mid-October, we initiated a shutdown of the crude and vacuum units and replaced catalyst in the distillate hydrotreater unit. In addition to advancing the re-certification of vessels in these units, the second shutdown included a significant improvement in our production of vacuum gas oil (“VGO”) thereby reducing the amount of VGO required to be purchased in the future to optimize the Isomax throughput. By early December, the refinery had returned to full operation with throughput averaging 109,611 bbl/d as compared to throughput of 90,440 bbl/d in September, 38,741 bbl/d in October and 35,981 bbl/d in November during the two shutdowns. This acceleration of planned shutdowns better positions us to benefit from anticipated higher margins in early 2008.

Comparatively, our refinery operating results for the period from October 19, 2006 through December 31, 2006 reflect the impact of an extended turnaround that commenced October 1, 2006 with the refinery returning to full operations near the end of November 2006. Our results for 2006 also include additional downtime in December as a result of a pipe rupture in the naphtha hydrotreater and a disruption in electric power service from the local utility which impacted the month’s throughput by approximately 3,000 bbl/d.

Refining Benchmark Prices

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

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

West Texas Intermediate (US$ per barrel)	61.60	83.03	72.31	60.44
Brent (US$ per barrel)	63.65	81.69	72.67	60.76
RBOB gasoline (US$ per barrel)	82.62	91.10	86.86	66.78
Heating Oil (US$ per barrel)	75.15	96.15	85.65	71.82
High Sulphur Fuel Oil (US$ per barrel)	45.11	62.93	54.02	40.94
2-1-1 Crack Spread (US$ per barrel)	17.29	10.60	13.95	8.86
Canadian / US dollar exchange rate	0.881	0.988	0.935	0.883

During 2007, the seasonality of the North American refining industry was evident as the “2-1-1 Crack Spread” averaged US$17.29 for the first six months of the year and US$10.60 for the last six months. The robust crack spreads during the first half of 2007 also reflected the impact of numerous refinery outages and an extremely tight gasoline supply situation in the Midwest US markets. As compared to the October 19, 2006 through December 31, 2006 period, RBOB gasoline and heating oil prices increased by 24% and 5%, respectively, during the first six months of 2007 while the WTI benchmark price increased a meager 2% resulting in a 95% increase in the “2-1-1 Crack Spread.”

During the six months ended December 31, 2007, RBOB gasoline and heating oil prices increased an additional 10% and 28%, respectively, as compared to the first six months of 2007 while the WTI benchmark price increased by 35% and the “2-1-1 Crack Spread” narrowed by 39% to US$10.60. The squeezing of refining margins during the second half of 2007 reflects a balanced alignment of crude oil prices with refined product pricing as well as an increase in available refining capacity with the resolution of the outages encountered earlier in the year.

The significant strengthening of the Canadian dollar during the last six months of 2007 had a significant financial impact on the results of our downstream operations. The 12% change in the Canadian / US dollar exchange rate between the first six months of 2007 and the last six months of the year compounded the 39% drop in the “2-1-1 Crack Spread” in US dollar terms to a 45% drop if converted to a Canadian dollar equivalent.

As compared to the “2-1-1 Crack Spread” industry indicator, our refinery’s production differs in that it also produces approximately 25% to 30% high sulphur fuel oil not represented in the “2-1-1 Crack Spread” indicator. High sulphur fuel oil typically sells US$15.00 to US$20.00 lower than the WTI benchmark price resulting in a negative contribution to our gross margin relative to the “2-1-1 Crack Spread.” However, our refinery also processes a medium gravity sour crude oil rather than a WTI quality of light sweet crude oil which sells at a discount to the WTI benchmark price and we purchase approximately 8,000 to 10,000 bbl/d of VGO to optimize the throughput of our Isomax unit at a premium price to the WTI benchmark price which further complicates the comparison of our refining margin to the “2-1-1 Crack Spread.”

Downstream Gross Margin

The downstream gross margin is comprised of the refining margins as well as the margin on our marketing and other related businesses. A comparison of the gross margin contribution from the refinery and marketing divisions for each of the first six months and last six months of 2007 is presented below:

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

Sales revenue⁽¹⁾	1,640,447	206,694	1,684,432	1,342,208	297,681	1,414,124
Cost of feedstock for
processing and products
for resale⁽¹⁾	1,317,886	185,761	1,340,938	1,278,021	274,520	1,326,776
Gross margin⁽²⁾	322,561	20,933	343,494	64,187	23,161	87,348

Average Refining
Margin (US$/bbl)	$13.69			$4.16

⁽¹⁾

Downstream operations sales revenue and cost of products for processing and resale are net of inter-segment sales of $162,709,000 and $225,765,000, reflecting the refined products produced by the refinery and sold by Marketing Division for the six months ended June 30, 2007 and December 31, 2007, respectively.

⁽²⁾

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

During 2007, our gross margin from refining totaled $386.7 million comprised of $322.6 million earned in the first six months of 2007 and $64.2 million earned in last six months of the year with our average refining margin for the year of US$10.05 per barrel of throughput comprised of US$13.69 for the first six months and US$4.16 for the last six months. The review of our refining margins is a combination of two analysis: (1) a comparison of refined product prices relative to the North American crude oil benchmark price, WTI, and (2) an analysis of the cost of our crude oil feedstock as compared to the WTI price.

The Marketing Division of our downstream operations is comprised of both retail and wholesale distribution of gasoline, home heating fuels and related appliances as well as the revenues from marine services including tugboat revenues. The Marketing Division has provided relatively stable gross margins with $9.8 million, $11.1 million, $11.8 million and $11.4 million reported for the first, second, third and fourth quarters, respectively, with the aggregate gross margin for 2007 totaling $44.1 million.

Refined Product Sales Revenue

Our refinery sales revenue is dependent on our yield of refined products and their sales value. Although our yield can be altered slightly to react to market conditions and seasonal demand, product yields are primarily impacted by the type of crude oil feedstock as well as refinery performance. Our sales volume closely approximates our production as the Supply and Offtake Agreement requires that substantially all refined products produced be purchased by Vitol Refining S.A. as they leave the refinery with the exception of jet fuel and certain other products marketed by our downstream marketing division primarily in the Province of Newfoundland and Labrador. The Supply and Offtake Agreement includes pricing formulas for refined product purchases whereby the price for refined products delivered from one Wednesday to the next is determined using average benchmark prices for the period commencing on the following Monday through Friday adjusted for actual shipping costs and product quality differentials. This pricing, which is based on a subsequent period, accelerates the impact of pricing trends on our sales prices and results in our prices being based on a slightly different time period than the monthly average benchmark prices, but generally, our refined product sales prices reflect the cost of crude oil feedstock, a refining crack spread and a quality differential adjustment with each impacted by global supply and demand. For more information on the Supply and Offtake Agreement, see the description of the Supply and Offtake Agreement in our Annual Information Form for the year ended December 31, 2007 to be filed on SEDAR at www.sedar.com.

A comparison of our refinery product yield, pricing and revenue for each of the first six months and last six months of 2007 is presented below.

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

Gasoline products	611,618	6,543	82.35/1.96	476,597	5,183	90.85/2.16
Low & ultra low
sulphur diesel & jet
fuel	727,656	8,066	79.48/1.89	611,732	6,179	97.81/2.33
High sulphur fuel oil	301,173	5,693	46.61	253,879	4,047	61.98
	1,640,447	20,302		1,342,208	15,409
Inventory adjustment		315			(262)
Total production		20,617			15,147

Yield (as a % of Feedstock) ⁽²⁾		99%			99%

⁽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

During 2007, gasoline product comprised 32% of our refinery output while ultra low sulphur diesel and jet fuel (or “distillates”) accounted for 40% and high sulphur fuel oil the residual 28%. Despite the two shutdowns in the last six months of 2007, our product yields during this period were substantially unchanged from the product slate produced during the first six months of the year. Our yield of 32% gasoline products and 40% distillates results in 72% of our production closely mirroring the “2-1-1 Crack Spread” benchmark.

Relative to the benchmark NYMEX RBOB gasoline price, our price for gasoline products closely mirrored the benchmark price with a minor difference of less than a US$0.01 per US gallon in both the first half and second half of 2007 as compared to a US$0.11 per US gallon discount in the period from October 19, 2006 through December 31, 2006. During the 2006 period, commodity prices were relatively stable resulting in the discount approximating the expected shipping cost to the New York Harbour. While in 2007, the expected shipping costs were offset by the benefit of a 10 day delay in a rising price environment.

For our ultra low sulphur diesel and jet fuel products, we realized a US$0.05 per US gallon premium over NYMEX heating oil prices during 2007 which is primarily attributed to the 10 day delay in our pricing in a rising price environment and to a lesser extent, our distillate products being generally a mix of higher valued distillate products than the benchmark heating oil product offset by the expected shipping cost to the New York Harbour. In addition, from time-to-time, there will be modest differences in the differential between the physical selling prices for our refined products in the New York Harbour and the NYMEX benchmark prices. The US$0.05 per US gallon average premium for 2007 is comprised of a US$0.10 per US gallon premium for the first six months and a US$0.04 premium during the last six months of the year. During the period from October 19, 2006 through December 31, 2006, we realized a US$0.03 per US gallon premium over the NYMEX heating oil benchmark price.

Our high sulphur fuel oil was sold at an average discount of US$19.03 per barrel relative to the WTI benchmark price in 2007 reflecting the heavier gravity and higher sulphur content of our fuel oil product. During the first six months of 2007, our high sulphur fuel oil sold at an average discount of US$14.99 per barrel as compared to US$21.05 during the last six months of the year.

Overall, relative to the WTI benchmark price, our refined products received a net premium of US$5.78 per barrel during 2007 comprised of US$9.59 in the first six months and US$3.03 in the last six months of the year.

Refinery Feedstock

We purchase crude oil feedstock from Vitol Refining S.A. pursuant to the terms of the Supply and Offtake Agreement which includes financing and operational hedging of crude oil pricing commitments. This enables the price of our feedstock to float with the WTI benchmark price for the period from pricing through to the date it is charged to the refinery. The Supply and Offtake Agreement includes pricing formulas for feedstock purchases similar to the pricing for refined product sales whereby there is a 10 day delay in pricing. This pricing based on a subsequent period accelerates the impact of pricing trends on the cost of our feedstock and results in our costs being based on a slightly different time period than the monthly average WTI benchmark price.

A comparison of crude oil and VGO feedstocks processed for each of the first six months and last six months of 2007 is presented below.

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

Basrah Light	859,308	13,795	54.88	749,048	9,435	78.44
Hamaca	172,501	2,879	52.79	190,367	2,301	81.74
Urals	152,007	2,246	59.63	85,442	1,121	75.30
Crude Oil
Feedstock	1,183,816	18,920	55.12	1,024,857	12,857	78.76
Vacuum Gas Oil	134,347	1,831	64.64	220,511	2,387	91.27
	1,318,163	20,751	55.96	1,245,368	15,244	80.72
Other costs	(277)			32,653
	1,317,886			1,278,021

⁽¹⁾

Cost of feedstock includes all costs of transporting the crude oil to refinery in Newfoundland

During 2007, our feedstock was comprised of 87,061 bbl/d of medium sour crude oil, (approximately 73% Basrah Light crude from Iraq, 16% Hamaca crude from Venezula and 11% Urals from Russia) and 11,556 bbl/d of VGO as compared to 80,767 bbl/d of crude oil (approximately 91% Basrah Light and 9% Hamaca), and 6,123 bbl/d of VGO in the prior year. We prefer to process Basrah Light feedstock due to its expected lower cost as compared to Hamaca and Urals while yielding a similar refined product slate and quality. The lower daily throughput during the period of October 19, 2006 to December 31, 2006 was the result of a turnaround that extended from the date of our acquisition of North Atlantic through to December 1, 2006. Similarly in 2007, daily throughput averaged 98,617 bbl/d for the year as two back-to-back shutdowns in the fourth quarter reduced the annual throughput which had averaged 111,052 bbl/d through the first nine months of the year.

Changes to our cost of feedstock reflect numerous factors beyond changes in the WTI benchmark price as our refinery competes for international waterborne barrels and the WTI benchmark price generally reflects a land-locked North American price with limited access to the Gulf Coast. The discount of Basrah Light relative to the WTI benchmark price is influenced by the quality of the crude as well as by the economics of other purchasers who may not be North American based nor deal in US dollars. On a monthly basis, the Oil Marketing Company of the Republic of Iraq announces its Official Selling Price (“OSP”) which is expressed in US dollars as a discount to the WTI benchmark price for North American deliveries and at the time of announcement, is equivalent to the discount to the Brent benchmark price in Euros for deliveries to Europe. Since our acquisition of North Atlantic in October 2006, the OSP has fluctuated from a low of US$3.30 in May 2007 to a high of US$13.05 in December 2007. The following graph summarizes the OSP for Basrah Light since January 2004 which relative to our US$10.05 average refining margin for 2007 demonstrates the significance of OSP pricing to our downstream performance:

Between the loading of the crude oil and its consumption, the OSP discount may change but for our load of Basrah Light, the OSP discount applicable at the time of loading does not change. For example, the OSP discount of US$6.90 in April 2007 was a component of the cost of our feedstock in June and July recognizing the 30 to 45 days to load in Iraq and ship to our refinery. While we are able to “operationally hedge” the WTI component of our feedstock costs between the date we commit to a purchase price and our processing of the crude, we are not able to effectively float the OSP component due to the lack of counterparty interest. As a result, the spike in the OSP discount in December 2007 to US$13.05 will significantly influence our refining margins in February and March 2008.

We also process Hamaca and Urals to complement our Basrah Light as a sufficient volume of Basrah Light is not always available and when other crudes are blended with Basrah Light, the blend may improve processing. During the first six months of 2007, we purchased Urals to ensure the refinery had ample crude oil feedstock and paid a premium as compared to Basrah Light. In July and August of 2007 when we processed the Urals, the WTI benchmark price was US$74.15 and US$72.36, respectively, which has resulted in our cost of Urals processed during the last six months of the year appearing to be lower than our cost of Basrah Light as the average WTI price for the last six months of 2007 of US$83.03 increased our cost of Basrah Light throughout the last half of the year. Typically, the price of Hamaca will closely track Basrah Light however the sharp increase in the OSP discount in late 2007 has resulted in the Hamaca crude becoming relatively more expensive.

In addition to VGO produced by our refinery, we purchase VGO as our Isomax unit’s processing capacity exceeds the VGO provided by our refinery from feedstock. In addition, we purchased incremental VGO during the third quarter of 2007 as we stockpiled VGO for use by the Isomax unit during the shutdown of the crude unit and vacuum tower in the fourth quarter. During 2007, VGO comprised approximately 9% of our total feedstock during the first half of the year and approximately 16% of total feedstock for the last six months of the year. Typically, VGO trades at a US$3.00 to US$5.00 premium to WTI due to the limited amount of processing required to yield a substantial volume of gasoline and diesel. However in late 2007, the VGO market was disrupted due to a refinery outage in the US Gulf Coast and concurrently, a reduction in VGO exports from Europe which resulted in the tightly balanced VGO market temporarily falling out of balance and the VGO premium to WTI temporarily spiked for a few months.

The cost of our crude oil feedstock during 2007 averaged US$64.99 per barrel comprised of US$55.12 in the first six months of the year and US$78.76 during the last six months, while the WTI benchmark price averaged US$72.31 for the year reflecting US$61.60 during the first half of the year and US$83.03 during the last half. During the first half of 2007, our average crude oil feedstock cost was US$6.48 per barrel less than the WTI benchmark price whereas for the last six months, our crude oil feedstock costs were US$4.27 per barrel less than the WTI benchmark price, consistent with narrowing of the Basrah Light OSP discount during the year.

The price of VGO during 2007 averaged US$78.66 per barrel as compared to the WTI benchmark price of US$72.31, a premium of US$6.35 for the year and a premium during the first six months averaging US$3.04 and US$8.24 during the last six months of the year.

The average cost of our feedstock in 2007 was US$66.59 per barrel comprised of a US$5.64 discount to the WTI benchmark price in the first six months and a US$2.31 discount during the last six months of the year. The reduced average discount in the last half of the year reflects an increased consumption of premium priced VGO feedstock combined with the narrowing in the Basrah Light OSP.

Refining Gross Margin

Our refining gross margin for 2007 aggregated to $386.7 million being a combination of crack spreads from gasoline, distillates and high sulphur fuel oil comprised of $322.6 million earned in the first half of the year and $64.2 million in the last half. During the first six months of 2007, our gasoline and distillates crack spreads, relative to the WTI benchmark price, were US$20.75 and US$17.88 per barrel, respectively, aggregating to an average crack spread of US$19.32 per barrel as compared to the “2-1-1 Crack Spread” of US$17.29 for the same period. We would anticipate our average gasoline/distillate crack spread to be higher than the “2-1-1 Crack Spread” benchmark as our distillate sold at a US$0.10 per US gallon premium over the NYMEX heating oil benchmark during the first six months of 2007. During the first six months of 2007, our high sulphur fuel oil sold at a US$14.99 discount to the WTI benchmark price and our feedstock cost was US$5.64 per barrel lower than the WTI benchmark price.

During the last six months of 2007, our gasoline and distillates crack spreads, relative to the WTI benchmark price, were US$7.82 and US$14.78 per barrel, respectively, aggregating to an average crack spread of US$11.30 as compared to the “2-1-1 Crack Spread” of US$10.60 for the same period. As expected, our average gasoline/distillate crack spread was US$0.70 per barrel higher than the “2-1-1 Crack Spread” benchmark as our distillates sold at a premium over the respective NYMEX benchmark prices during this period but primarily due to the 10 day delay in pricing our refined products pursuant to the Supply and Offtake Agreement during a period when NYMEX gasoline and NYMEX heating oil price rose an average of 10% and 28%, respectively. During the last six months of 2007, our high sulphur fuel oil sold at a US$21.05 per barrel discount to the WTI benchmark price (a US$6.06 reduction in price as compared to the first six months of the year) and our feedstock cost was US$2.31 per barrel lower than the WTI benchmark price, an increase of US$3.33 per barrel in our feedstock costs relative to the WTI benchmark price.

During the first six months of 2007, robust refining margins combined with our refinery operating at near name plate capacity to generate $322.6 million of gross margin (US$13.69 per barrel of throughput) as compared to $64.2 million (US$4.16 per barrel of throughput) during the last six months of the year. The $258.4 million reduction in gross margin during the last six months of 2007 as compared to the first six months of the year is comprised of a $172.7 million variance attributed to reduced crack spreads and an $85.7 million unfavourable variance due to reduced throughput. Included in the reduced crack spreads is a $25.7 million unfavourable variance due to the strengthening of the Canadian dollar relative to the US dollar denominated crack spread pricing.

For the period from October 19, 2006 to December 31, 2006, our refining gross margin totaled $67.0 million comprised of $83.7 million from the sale of gasoline and distillate products refined from crude oil feedstock and $9.7 million from gasoline and distillate refined from VGO offset by a $26.4 million negative margin from the production of high sulphur fuel oil.

Operating Expenses

The following summarizes the operating costs from the refinery and marketing division for each of the first six months and last six months of 2007:

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

Operating expense	43,153	8,792	51,945	40,782	9,749	50,531
Turnaround and catalyst	-	-	-	34,486	-	34,486
Purchased energy	42,337	-	42,337	49,991	-	49,991
	85,490	8,792	94,282	125,259	9,749	135,008

The largest component of our refining operating expense is wages and benefits which totaled $59.6 million during 2007 (2006 - $11.2 million) while the other significant components were maintenance and repairs costs of $14.6 million (2006 - $2.1 million), insurance of $7.0 million (2006 - $1.4 million) and professional services of $6.4 million (2006 - $0.8 million). During the year ended December 31, 2007 refining operating expenses were $2.33 per barrel as compared to $2.34 per barrel in the prior period consistent with our expectations of approximately $2.20 to $2.40 per barrel. The marketing division’s operating costs run approximately $4.5 million per quarter aggregating to $18.5 million for 2007.

Turnaround and catalyst expenditures of $22.1 million and $12.4 million, respectively, were incurred during the two planned shutdowns in 2007. Catalyst expenditures include the planned biannual top-bed catalyst change-out on the hydrocracker unit and the replacement of the catalyst on the distillate hydrotreater unit. Turnaround expenditures include planned major maintenance completed simultaneously with the catalyst change-out on both the Isomax, and crude unit. The accelerated shutdown of the crude unit and vacuum tower, originally scheduled for the spring of 2008, contributed an incremental $17.0 million and $7.4 million to turnaround and catalyst expenditures, respectively.

Purchased energy, consisting of low sulphur fuel oil and electric power, is required to provide heat and power to refinery operations, respectively. Our purchased energy costs increased to $2.56 per barrel during 2007 as compared to $2.47 per barrel during 2006 as a result of the increased price of fuel oil.

Marketing Expense

During the year ended December 31, 2007 marketing expense, in conjunction with the Supply and Offtake Agreement, is comprised of $3.4 million of marketing fees (based on US $0.08 per barrel of feedstock) to acquire feedstock ($0.5 million in the period October 19, 2006 to December 31, 2006) and $31.6 million of “Time Value of Money” charges ($4.6 million in the period October 19, 2006 to December 31, 2006).

Capital Expenditures

Capital spending for the year ended December 31, 2007 totaled $44.1 million including $8.0 million for tank maintenance and recertification, $6.3 million to replace heat exchanger bundles, $4.8 million for re-piping of the crude unit and vacuum tower as well as approximately $2.0 million of an estimated $27 million to enhance our visbreaker capacity which is expected to be completed in the fourth quarter of 2008.

Depreciation and Amortization Expense

The following summarizes the depreciation and amortization expense for 2007 and 2006:

	Year Ended December 31, 2007			For the Period October 19, 2006 to December 31, 2006
(000’s of Canadian dollars)	Refining	Marketing	Total	Refining	Marketing	Total

Tangible assets	64,251	2,071	66,322	13,833	410	14,243
Intangible assets	4,781	1,497	6,278	1,049	190	1,239
	69,032	3,568	72,600	14,882	600	15,482

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

Goodwill

On October 19, 2006, we recorded $203.9 million of goodwill with our acquisition of North Atlantic as the purchase price of the acquired business exceeded the fair value of the net identifiable assets and liabilities. As the refining assets are held in a self-sustaining subsidiary with a US dollar functional currency, the value of the goodwill is adjusted at the end of each accounting period to reflect the current US dollar exchange rate.

We assess goodwill for impairment annually, or more frequently if events or changes in circumstances warrant. We compare the fair value of our downstream assets and liabilities to their carrying value as well as evaluate the future cash flow projections of our downstream operations in light of the current outlook of the refining industry. Our assessment for the year ended December 31, 2007 concluded that the fair value of our downstream assets exceeds their carrying value and that future cash flows support the carrying value of the goodwill recorded in the accounts. For the year ended December 31, 2006, no charge for impairment was made.

RISK MANAGEMENT, FINANCING AND OTHER Cash Flow Risk Management

Our cash flow risk management program includes a detailed analysis of the impact of changes in crude oil prices, natural gas prices, the US/Canadian dollar exchange rate and subsequent to acquiring the downstream operation in late 2006, certain refined product prices. While we anticipate our upstream operations will produce approximately 47,000 bbl/d of crude oil and 93,000 mcf/d of natural gas in 2008, our cash flow at risk is determined after deducting the royaltyholders’ interest of approximately 9,000 bbl/d and 16,000 mcf/d, respectively. The crude oil produced by our upstream operations in western Canada does not physically flow to our refinery in the Province of Newfoundland and Labrador but for purposes of our cash flow at risk model, our cash flow from producing crude oil is financially integrated with our requirement to purchase crude oil feedstock for our downstream operations. As a result, our 2008 cash flow at risk is comprised of approximately 38,000 bbl/d of refined product prices and 77,000 bbl/d of refined product crack spreads as well as 77,000 mcf/d of western Canadian natural gas prices. Our refined product crack spread is the difference between the cost of our crude oil feedstock and the sales value of our refined products. Using forecast prices for 2008, our cash flow at risk model projects 2008 net revenues will be comprised of 66% refined product revenues, 21% refined product crack spreads and 13% western Canadian natural gas prices. Prior to acquiring the downstream operations, our cash flow at risk was limited to western Canadian crude oil prices and natural gas prices as well as the US/Canadian dollar exchange rate.

2008 Integrated Liquids Position:

We enter into pricing contracts with financial counterparties for periods of up to two years whereby we receive a predetermined price as per the contract and the counterparty receives a market price over the term of the contract. Commencing in 2006, we have limited our counterparties to lenders in our syndicated credit facility as the security provided under our credit agreement extends to our pricing contracts. This eliminates the requirement for margin calls and the pledging of collateral as well as enables the negotiation of a more limited number of events of default, all of which contribute to ensuring the contracts are in place for the contracted term and limit the potential for these contracts to exacerbate credit concerns. Typically, a significant mark-to-market deficiency in pricing contracts will heighten the counterparty’s credit concerns; however, when the counterparty also participates in a related credit facility, the same commodity price increase giving rise to the mark-to-market credit concern should also provide offsetting credit comfort with respect to the credit facility as an increase in commodity prices should result in an appreciation in the value of the underlying assets securing the credit facility.

Prior to 2007, our pricing contracts were limited to WTI prices as publicly traded on the New York Merchantile Exchange (“NYMEX”) and AECO natural gas prices as reported on the industry trading exchange. Commencing in 2007, the pricing terms of our refined product price contracts were limited to publicly traded benchmark prices on either the NYMEX or the Platts Index. By limiting the price basis to publicly traded benchmark prices, our price contracts should be sufficiently liquid as to enable an efficient unwinding of contracted positions should we encounter a disruption in production. Our execution of a refined product price contract combines the price protection of both the crude oil price (the “WTI” benchmark price) as well as the related refined product crack spread (either RBOB gasoline, heating oil or #6 fuel oil). The use of refined product price contracts consolidates credit requirements and results in a combining of the volatility of the WTI benchmark price with the volatility of the crack spread for refined product. In 2007, we have used a combination of “price collars” which provides a fixed floor price and price cap as well as a “three way” structure which provides a floor price with a premium over market price on the downside and a price cap. In the future, we may also use “fixed price swap” contracts which provide a “fixed price” and/or ”participating swap” contracts which provide a firm floor price with a percentage participation in prices above the floor price. Details of our commodity price contracts outstanding at December 31, 2007 are included in Note 19 of our consolidated financial statements filed on SEDAR at www.sedar.com.

The table below provides a summary of the net gains and losses realized on our price risk management contracts for each of the years ended December 31, 2007 and 2006:

	Crude		Natural		Currency			Electric	Total
(in 000s)		Oil		Gas	Exchange Rates			Power

Year ended December 31, 2007	$	(41,462)	$	6,299	$	5,725	$	3,147	$	(26,291)

Year ended December 31, 2006	$	(80,832)	$	4,838	$	1,801	⁽¹⁾ $	11,574	$	(62,619)

⁽¹⁾

Excludes $17.8 million realized on the series of US dollar forward purchase contracts entered into with respect to the purchase of North Atlantic.

During 2007, the net realized loss on price risk management contracts totaled $26.3 million, a $36.3 million reduction from the prior year substantially all related to our crude oil price contracts. The principal difference in our crude oil price contracts was the increase in the floor price to US$57.18 per bbl plus 70% participation on prices above US$57.18 in 2007 as compared to a floor price of US$43.80 plus 60% participation on prices above US$43.80 in 2006. With the average WTI price increasing US$6.07 from US$66.24 in 2006 to US$72.31 in 2007, the US$13.38 increase in our contracted floor price as well as the 10% higher participation level on prices in excess of the contracted floor price combined to reduce the losses realized on our crude oil contracts by $39.4 million in 2007 as compared to the prior year. The volume hedged averaged 23,750 bbl/d in 2006 and 27,500 bbl/d in 2007 which represented approximately 66% and 76% of our net production, respectively. The following charts present the average monthly WTI prices and the contracted crude oil price settlement in our oil pricing contracts for each of 2006 and 2007:

Year ended December 31, 2006

Year ended December 31, 2007

Typically, we enter into natural gas price contracts that provide a firm floor price in exchange for a price cap for the contract year (April through March of the following year) in anticipation of soft prices during the summer months. In 2007, we received $6.3 million primarily from our contracting for natural gas price protection on 30,000 GJ/d at a floor price equal to the greater of $7.00 per GJ or market price plus $2.00 for the period from April 2007 through March 2008 of which $5.5 million was received when we unwound the position in July 2007. In 2006, we had “price collar” contracts in place that provided floor prices on 25,000 GJ/d at $5.00 per GJ and with respect to a further 25,000 GJ/d, $7.00 per GJ. Substantially all of the $4.8 million gain in 2006 related to the natural gas price contract with the $7.00 floor price.

In 2007, the $5.7 million gain realized on our currency exchange rate contracts reflect the significant strengthening of the Canadian dollar relative to the US dollar from Cdn$1.1654 per US dollar at January 1, 2007 to Cdn$0.9913 on December 31, 2007. During 2007, we had US$8.7 million per month contracted at an exchange rate of Cdn$1.1228 per US dollar for the entire year which generated substantially all of the $5.7 million benefit while a further US$10 million contracted with a collar of Cdn$1.0000 and Cdn$1.0550 per US dollar added limited benefit. In addition, see the Currency Exchange discussion in this MD&A.

We also enter into fixed price electric power contracts to provide protection from rising power prices in Alberta. In 2007, Alberta’s electric power prices averaged $66.84 per megawatt hour as compared to $80.48 in 2006. Relative to our $11.6 million gain realized in 2006, the $3.1 million benefit received in the current year from our fixed price electric power contracts reflects generally lower prices as well as an increase in the contracted fixed price from $51.48 per MWh in 2006 to $56.69 in 2007. Typically, our fixed price electric power contracts represent approximately 50% of our anticipated electrical power consumption and for 2008, we have fixed price contracts for 35 MWh for the period from January 2008 through December 2008 at a price of $56.69.

During 2007, we entered into the following refined product price contracts:

For the period from January 2008 through December 2008

12,000 bbl/d of NYMEX heating oil,
8,000 bbl/d of Platts heavy fuel oil,
6,000 bbl/d of NYMEX heating oil crack spread, and
2,000 bbl/d of Platts heavy fuel oil crack spread.

For the period from July 2008 through December 2008

6,000 bbl/d of NYMEX RBOB gasoline comprised of an RBOB crack contract and a WTI price contract.

For the period from January 2009 through June 2009

12,000 bbl/d of NYMEX heating oil, and
8,000 bbl/d of Platts heavy fuel oil.

In addition, we have contracted for 10,000 bbl/d of WTI prices for the first half of 2008 with an average floor price of US$60.00 and participation in 73% of the upside above US$60.00 which was placed prior to our acquisition of the downstream business. In respect of our refined product price and WTI price exposures, these contracts represent approximately 79% of our exposure for the first half of 2008, 68% for the second half of 2008 and 53% for the first half of 2009. With respect to our cash flow exposure related to refined product crack spreads, our contracts represent approximately 10% of our crack spread exposure for 2008.

The table below provides a summary of net unrealized gains and losses recorded for our price risk management contracts for each of the years ended December 31, 2007 and 2006 which reflects the change in period end unrealized gains and losses:

	Crude			Refined	Natural		Currency			Electric	Total
(in 000s)		Oil		Products		Gas	Exchange Rates			Power

Year ended December 31, 2007	$	(14,601)	$	(138,801)	$	(596)	$	13,904	$	(7,687)	$	(147,781)

Year ended December 31, 2006	$	53,820		-	$	(662)	$	(5,309)	$	3,932	$	51,781

At the end of 2007, the mark-to-market deficiency on our refined product and WTI price contracts was $138.8 million and $24.9 million, respectively, while the mark-to-market value of our natural gas, currency exchange rate and electrical power price contracts aggregated to $14.0 million. Our 2008 refined product contracts were placed in mid-2007 when the WTI benchmark price was approximately US$71.00 and the NYMEX price of heating oil and Platts Index for fuel oil were approximately US$2.00 per gallon and US$55.00 per barrel, respectively, as compared to the 2007 year end closing prices of US$95.98 for WTI, US$2.64 per gallon for NYMEX heating oil and US$75.15 per barrel for Platts fuel oil. While our contracted prices for 2008 are higher than prices received in 2007, the 2007 year end prices for WTI and refined products were higher still which has resulted in the significant mark-to-market deficiency. At the end of 2007, we had a modest 276 GJ/d of natural gas price contracts in place through December 2008.

While modest compared to our refined product position, we have contracted a fixed exchange rate on US$8.3 million per month for the period from January 2008 through June 2008 averaging Cdn$1.11 per US$1.00 and collared an exchange rate of Cdn$1.00 to Cdn$1.055 on a further US$10 million per month covering January 2008 through December 2008. These contracts had a mark-to-market value of $8.6 million at the end of 2007. For 2008, approximately 52% of our Alberta power consumption is fix priced at $56.69 and mark-to-market value of this contract was $5.6 million at the end of 2007.

Interest Expense

	Year Ended December 31

(000s)		2007		2006	Change
Interest on short term debt
Bank loan	$	1,275	$	1,489	(14%)
Convertible Debentures		2,498		-	100%
Amortization of deferred finance charges – short term debt		1,811		3,375	(46%)
		5,584		4,864	15%

Interest on long-term debt
Bank loan		70,204		30,967	127%
Convertible Debentures		56,740		20,229	180%
77/8% Senior Notes		22,561		22,624	-%
Amortization of deferred finance charges – long term debt		2,696		5,073	(47%)
		152,201		78,893	93%
Total interest expense	$	157,785	$	83,757	88%

Interest expense, which includes the amortization of related financing costs, was $74.0 million higher in 2007 than the prior year. Of this increase, $39.0 million is attributed to increased short and long term bank loan interest resulting from the significant increase in bank debt to finance the acquisitions of North Atlantic in October 2006 and to a lesser extent, Grand in August 2007. An additional $39.0 million of interest expense was incurred in 2007 compared to 2006 due to the increased principal amount of Convertible Debentures outstanding, offset by a $3.9 million reduction in the amortization charge for deferred financing costs.

At December 31, 2007, we had drawn approximately $1,279.5 million of bank borrowings as compared to $1,595.7 million at December 31, 2006. During the First Quarter of 2007, our bank borrowings were reduced with the net proceeds of $357.4 million from our issuance of 6,146,750 Trust Units and $230 million principal amount of 7.25% Debentures due 2014. During the Second Quarter of 2007, our bank borrowings were reduced by a combination of net proceeds of $218.5 million from our issuance of 7,302,500 Trust Units and surplus cash from operating activities after capital spending and distribution requirements. In the Third Quarter of 2007, we increased our bank borrowings by $157.0 million, of which $139.3 million is attributed to the acquisition of Grand during the quarter. Our bank borrowings were further increased by $74.4 million in the Fourth Quarter, as our cash distributions and capital spending exceeded our cash flow from operating activities by $61.1 million. Currently, the interest on our Three Year Extendible Revolving Facility is at a floating rate based on 70 basis points over bankers’ acceptances for Canadian dollar borrowings and 70 basis points over the London Inter Bank Order Rate for US dollar borrowings. During the year ended December 31, 2007, our interest charges on bank loans aggregated to $71.6 million, reflecting effective interest rates of 5.28% and 6.08% for the Canadian and U.S. amounts drawn, respectively. Further details on our credit facilities are included under “Liquidity and Capital Resources”.

The interest on our Convertible Debentures totaled $59.2 million during the year ended December 31, 2007, and is based on the effective yield of the debt component of the Convertible Debentures. Details on the Convertible Debentures outstanding are fully described in Note 12 to the audited consolidated financial statements for the year ended December 31, 2007 filed on SEDAR at www.sedar.com. During the year ended December 31, 2007, there were $161.1 million of principal amount Convertible Debentures converted to 5,922,708 Trust Units.

The interest on our 77/8% Senior Notes totaled $22.6 million for the year ended December 31, 2007. Like our Convertible Debentures, interest expense is based on the effective yield, and as a result, the interest expense recorded is greater than the cash interest paid. Due to the recent strength of the Canadian dollar relative to the U.S. dollar, our cash interest expense has been lowered as interest on these notes is paid in U.S. dollars, however our non-cash interest expense has increased due to the adoption of the revised standard on financial instruments. See Note 3 of the consolidated financial statements for the year ended December 31, 2007 filed on SEDAR at www.sedar.com.

Included in short and long term interest expense is the amortization of the discount on the 77/8% Senior Notes, the accretion on the debt component balance of the Convertible Debentures to face value at maturity, as well as the amortization of commitment fees and legal costs incurred for our credit and bridge facilities, all totaling $4.5 million for the year ended December 31, 2007.

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 LIBOR bank loans, 77/8% Senior Notes as well as any other U.S. dollar cash balances. Since December 31, 2006, the Canadian dollar has strengthened significantly compared to the U.S dollar. As a result we have earned an unrealized foreign exchange gain on our 77/8% Senior Notes of $42.3 million during the year ended December 31, 2007. In the Third Quarter of 2007, we repaid our U.S. dollar denominated LIBOR bank loans that were incurred in connection with our purchase of North Atlantic, realizing a foreign exchange gain of $43.5 million in the quarter and $47.1 million year-to-date in respect of this loan. In addition, during the year ended December 31, 2007 we also incurred unrealized foreign exchange losses and realized foreign exchange gains on North Atlantic transactions of $10.6 million and $4.7 million, respectively.

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. In 2007, the strengthening of the Canadian dollar relative to the U.S. dollar resulted in a $243.6 million cumulative translation loss as the stronger Canadian dollar results in a decrease in the relative value of our downstream net assets.

Future Income Tax

During 2007, there were two significant Canadian income tax changes that impacted our accounting for future income taxes. On June 22, 2007, Bill C-52 became law and on December 14, 2007, Bill C-28 became law. Bill C-52 contains provisions to implement the proposals to tax publicly traded income trusts and as a result, we recorded a $255.0 million future income tax charge during the second quarter of 2007 to apply an expected tax rate to the temporary differences between the book value and the tax basis of our assets held by our mutual fund trust and other “flow through” vehicles as forecasted on the effective date of the tax change, January 1, 2011. Concurrent with the recording of this non-cash future income tax expense, we also recorded an offsetting future income tax asset of $77.3 million to reflect the application of the current and expected future tax rates to the temporary differences between the book value and the tax basis of assets held by our corporate entities on June 30, 2007 which had not been previously reflected due to the lack of assurance that the benefit of this tax asset would be realized.

Bill C-28 contains the provisions to implement reductions in the federal corporate income tax rates. The federal corporate income tax rate will be reduced from 20.5% to 19.5% in 2008 with further reductions scheduled resulting in a 15% tax rate as of January 1, 2012. These rate reductions also apply to the expected tax rate applicable to our mutual fund trust and other ”flow through” vehicles. Accordingly, in the fourth quarter of 2007, we adjusted our future income tax provision to reflect these reduced tax rates.

As at the end of 2007, we have a net future income tax provision on our balance sheet totaling $86.6 million comprised of a $270.5 million provision for our mutual fund trust and other “flow through” entities and a net asset of $183.9 million for our corporate entities. The net provision for our mutual fund trust and other “flow through” entities will be reviewed for changes in our forecasted temporary differences and legislative tax rate changes both as of January 1, 2011. The future income tax asset recorded by our corporate entities will fluctuate during each accounting period to reflect changes in the respective temporary differences between the book value and tax basis of their assets as well as further legislative tax rate changes.

Currently, the principal source of our corporate entities’ temporary differences is the difference between our net book value of our property, plant and equipment versus our unclaimed tax pools and the recognition for accounting purposes of a mark-to-market deficiency on our risk management contracts. Future income tax recoveries from of our corporate entities may fully offset the future income tax provision of our mutual fund trust and other “flow through” entities prior to 2011.

In our current structure, payments in respect of net profits interests and interest on inter-entity debt are made between our operating entities and our mutual fund trust which ultimately transfers both taxable income and the income tax liability to the holders of our Trust Units. As a result, no cash income taxes have been paid by Harvest, However, effective January 1, 2011, Harvest will become subject to the provisions of Bill C-52 should Harvest remain in its current structure. At the end of 2007, we estimate our tax pools to be as follows:

				Upstream	Downstream
Tax Classification (in millions)		Trust		Operations	Operations			Total

Canadian Oil & Gas Property Expenditures	$	550	$	310	$	-	$	860
Canadian Development Expenditures		-		230		-		230
Unclaimed Capital Costs		-		500		420		920
Non-capital losses and other		40		570		150		760
Total	$	590	$	1,610	$	570	$	2,770

Contractual Obligations and Commitments

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

	Maturity
Annual Contractual Obligations (000s)	Total	Less than 1 year	1-3 years	4-5 years	After 5 years
Long-term debt⁽²⁾	1,527,326	-	1,279,501	247,825	-
Interest on long-term debt⁽⁴⁾	233,881	88,216	130,319	15,346	-
Interest on Convertible Debentures⁽³⁾	252,454	46,832	92,916	86,063	26,643
Operating and premise leases	27,362	7,572	12,397	7,145	248
Purchase commitments⁽⁵⁾	17,224	15,924	1,300	-	-
Asset retirement obligations⁽⁶⁾	1,002,893	24,617	17,350	27,437	933,489
Transportation ⁽⁷⁾	6,110	2,249	2,953	861	47
Pension contributions	31,360	1,143	3,631	5,301	21,285
Feedstock commitments	843,583	843,583	-	-	-
Total	3,942,193	1,030,136	1,540,367	389,978	981,712

⁽¹⁾

As at December 31, 2007, we had entered into physical and financial contracts for production with average deliveries of approximately 8,000 bbl/d for 2008. We have also entered into financial contracts for our downstream production of refined products with average deliveries of approximately 34,000 bbl/d in 2008 and 10,000 bbl/d in 2009. We have also entered into financial contracts to minimize our exposure to fluctuating electricity prices. Please see Note 18 to the consolidated financial statements for further details.

⁽²⁾

Assumes that the outstanding Convertible Debentures either convert at the holders’ option or are redeemed for Units at our option.

⁽³⁾

Assumes no conversions and redemption by Harvest for Trust Units at the end of the second redemption period. Only cash commitments are presented.

⁽⁴⁾

Assumes constant foreign exchange rate. (5) Relates to drilling commitments, AFE commitments and downstream purchase commitments.

⁽⁶⁾

Represents the undiscounted obligation by period

⁽⁷⁾

Relates to firm transportation commitment on the Nova pipeline.

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

Off Balance Sheet Arrangements

As at December 31, 2007, we have no off balance sheet arrangements in place.

Related Party Transactions

During the year ended December 31, 2007, Vitol Refining S.A. purchased U.S. $388.8 million of Basrah Light crude oil pursuant to the terms and conditions of the Supply and Offtake Agreement from a company in which a director of Harvest holds a minority equity interest. As at December 31, 2007, no amount related to these purchases is included in Harvest’s accounts payable and accrued liabilities, and $68.0 million is included in the total feedstock commitments disclosed at the end of December 2007. Subsequent to December 31, 2007, no further commitments have been incurred relating to crude oil purchases by Vitol Refining S.A from this private company.

CHANGE IN ACCOUNTING POLICIES

Effective January 1, 2007, we have retrospectively without restatement adopted the new accounting standards of the Canadian Institute of Chartered Accountants respecting, “Financial Instruments – Recognition and Measurement”; “Comprehensive Income”; and “Financial Instruments – Disclosure and Presentation”. The impact of adopting these new standards is reflected in our financial results for the year ended December 31, 2007 while the prior year comparative financial statements have not been restated. While the new standards change how we account for financial instruments, there were no material impacts on our results for the year ended December 31, 2007, with the most significant difference being that certain deferred charges previously presented as an asset are now netted against the respective debt and amortized to income using an effective interest rate. For a description of the new accounting standards and the impact on our financial statements of adopting such standards see Note 3 to the consolidated financial statements for the year ended December 31, 2007.

LIQUIDITY AND CAPITAL RESOURCES

During 2007, cash flow from operating activities was $641.3 million, including a reduction of $17.4 million in respect of non-cash working capital with the significant components of this being a $39.9 million reduction in accounts payable and a $34.5 million increase in downstream inventories offset by a $51.5 million reduction in accounts receivable. Cash flow from operating activities before changes in non-cash working capital totaled $658.7 million. We declared distributions of $610.3 million, required $344.8 million for capital expenditures and raised $178.5 million with our distribution re-investment plans. The net cash requirement of $135.3 million was funded with bank borrowings.

During the year, our net bank borrowings decreased by $316.2 million primarily from the $576.0 million of net proceeds from the issuance of $230.0 million of principal amount of Convertible Debentures and 13,499,250 Trust Units offset by the $135.3 million required for our capital expenditure program and $138.2 million for our property acquisition and disposition activity. Our upstream acquisition and disposition activity required funding as the $60.6 million of net proceeds we realized from the disposition of 885,000 barrels of proved reserves (at an average of $68.47 per boe) were more than offset by our investment of $198.7 million in an additional 7,283,000 barrels of proved reserves, including the acquisition of Grand Petroleum Inc., at an average cost of $27.29 per boe.

During the fourth quarter of 2007, cash flow from operating activities was $88.0 million, including $16.6 million in respect of a reduction in non-cash working capital with the more significant components being a $26.9 million reduction in accounts payable offset by a $29.9 million reduction in accounts receivable and a $6.1 million reduction in downstream inventories. Cash flow from operating activities before changes in non-cash working capital totaled $71.4 million. We declared distributions of $144.7 million, required $47.5 million for capital expenditures and raised $43.1 million with in our distribution re-investment plans. The net cash requirement of $61.1 million was funded by an increase in bank borrowings.

For the year ended December 31, 2006, cash flow from operating activities was $507.9 million, including a $28.2 million reduction in respect of non-cash working capital with the more significant components being a $55.5 million increase in accounts receivable offset by a $17.9 million increase in accounts payable and a $6.0 million increase in distributions payable. Cash flow from operating activities before changes in non-cash working capital totaled $536.0 million. We declared distributions of $468.8 million, required $398.3 million for capital expenditures and received $167.5 million from participation in our distribution re-investment plans. The net cash requirement of $191.7 million was funded with bank borrowings.

At the end of 2007, we had $320.5 million of unutilized borrowing capacity from our $1.6 billion Three Year Extendible Revolving Credit Facility as compared to $94.0 million of unutilized capacity under a $1.4 billion credit facility at the beginning of the year. In April 2007, we increased this facility from $1.4 billion to $1.6 billion and with the exception of $65 million of lending commitments which retained a March 2009 maturity date, extended the maturity date of our Three Year Extendible Revolving Credit Facility to April 2010. In October 2007, we re-assigned the $65 million of non-extending lender commitments to other lenders in our banking syndicate and concurrently extended the maturity date on this incremental commitment to April 2010. In late 2007, the much publicized sub-prime mortgage/asset backed commercial paper crisis had resulted in a tightening of credit availability and a general re-pricing of credit. As we do not generally maintain any surplus cash, we have no direct exposure to asset backed commercial paper. As the disruptions in the capital markets continue, we are comfortable with the April 2010 maturity date for our credit facilities and may elect to defer extending the maturity date until capital market conditions improve.

Our cash flow risk management program includes our entering into numerous pricing contracts. We have limited our counterparties to the lenders in our syndicated credit facilities as the security provided in our credit agreement extends to our pricing contracts and this eliminates the requirement for margin calls and the pledging of collateral as well as limits the negotiation of events of default, all of which contribute to ensuring that these contracts improve our liquidity rather than exacerbate credit concerns.

The following table summarizes our capital structure for each of the years ended December 31, 2007 and 2006:

	As At December 31

(in millions)	2007	2006
DEBT
Credit Facilities
- Three Year Extendible Revolving Credit Facility	$1,279.5	$1,306.0
- Senior Secured Bridge Facility	-	289.7
Total Bank Debt	1,279.5	1,595.7

7 7/8 % Senior Notes Due 2011 (US$250 million)⁽¹⁾	247.8	291.4

Convertible Debentures, at principal amount
10.5% Debentures Due 2008	24.3	26.6
9% Debentures Due 2009	1.0	1.2
8% Debentures Due 2009	1.7	2.2
6.5% Debentures Due 2010	37.1	37.9
6.4% Debentures Due 2012	174.6	174.8
7.25% Debentures Due 2013	379.3	379.5
7.25% Debentures Due 2014	73.2	-
Total Convertible Debentures	691.2	622.2

Total Debt	2,218.5	2,509.3

TRUST UNITS
148,291,170 issued at December 31, 2007	3,736.1
122,096,172 issued at December 31, 2006		3,046.9
TOTAL OF DEBT AND TRUST UNITS	$5,954.6	$5,556.2

⁽¹⁾

Face value converted at the period end exchange rate.

During 2007, the significant changes to our capital structure were:

Issuance of $230 million principal amount of 7.25% Debentures Due 2014 and 6,146,750 Trust Units in February with net proceeds of $357.4 million used to repay the Senior Secured Bridge Facility and reduced borrowings on our Three Year Extendible Revolving Credit Facility by $67.7 million,
Extension of our Three Year Extendible Revolving Credit Facility’s maturity date to April 2010 and a $200 million increase in the aggregate commitment to $1.6 billion,
Issuance of a further 7,302,500 Trust Units in June to reduce borrowings on our Three Year Extendible Revolving Credit Facility by $218.5 million,
Issuance of 5,922,708 Trust Units on the conversion of $161.1 million of principal amount of Convertible Debentures, and
Issuance of 6,809,987 Trust Units pursuant to Harvest’s Premium DistributionTM, Distribution Reinvestment and Optional Trust Unit Purchase Plan (the “DRIP Plans”) raising $178.5 million.

Concurrent with the closing of the Plan of Arrangement with Viking on February 3, 2006, we entered into a covenant-based Three Year Extendible Revolving Credit Agreement and have amended this agreement to extend the maturity to April 2010 and upsized the facility from an initial $750 million commitment to $1.6 billion. This facility is secured by a $2.5 billion first floating charge over all of our assets and generally contains typical covenants with the most restrictive being an aggregate limitation of $25 million on financial assistance and/or capital contributions to parties other than those included in the first floating charge debenture, a limitation to carrying on business in countries that are not members of the Organization of Economic Co-operation and Development and limitations on payments of distributions in certain circumstances such as an event of default. The credit facility contains floating interest rates that are expected to range between 65 and 115 basis points over bankers’ acceptance rates (currently 70 bps) depending on the ratio of our secured senior debt (excluding 77/8% Senior Notes and Convertible Debentures) to earnings before interest, taxes, depletion, amortization and other non-cash amounts (“EBITDA”) with availability under this facility subject to:


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

At December 31, 2007, our Bank Debt to annualized EBITDA was 1.5 to 1.0, Total Debt (excluding Convertible Debentures) to annualized EBITDA was 1.8 to 1.0, while the Bank Debt to Total Capitalization was 29% and Total Debt to Total Capitalization was 34%. For a complete description of our covenant-based credit agreement, see Note 11 to our audited consolidated financial statements for the year ended December 31, 2007 filed on SEDAR at www.sedar.com.

In October 2004, Harvest Operations Corp., a wholly-owned subsidiary of Harvest, issued US$250 million of principal amount 77/8% Senior Notes for net proceeds of $312.0 million Canadian dollars. These 77/8% Senior Notes are unsecured, require semi-annual payments of interest and provide for the following permitted redemptions:

Beginning on October 15, 2007 at 103.938% of the principal amount ⁽¹⁾ ;
After October 15, 2007 at 103.938% of the principal amount;
After October 15, 2009 at 101.969% of the principal amount; and,
After October 15, 2010 at 100% of the principal amount.

⁽¹⁾

Only permitted if necessary to prevent the Trust from being disqualified as a mutual fund trust for purposes of the Income Tax Act (Canada). Limited to 30% of the notes issued or less; otherwise 100% of the notes issued.

These 77/8% Senior Notes contain certain covenants restricting, among other things, the sale of assets and 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 our secured indebtedness to an amount 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 the end 2007, 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 $1.86 billion.

At the end of 2007, we had $691.2 million of principal amount of Convertible Debentures issued in seven series with $64.0 million of principal amount due prior to 2012 and $627.2 million of principal amount due beyond 2011. Prior to maturity, these Convertible Debentures are convertible into Trust Units of Harvest, at the option of the holder, at the conversion price per Trust Unit specified for each series and may be redeemed at our option at a price equal to $1,050 per debenture during the first redemption period and $1,025 per debenture during a second redemption period. At maturity or upon redemption, the principal repayment obligation may be settled in the form of Trust Units at a price equal to 95% of the weighted average trading price for the preceding 20 consecutive trading days five days prior to the settlement. On January 31, 2008, we settled the maturity of $24.3 million principal amount of the 10.5% Convertible Debentures with the issuance of 1,116,593 Trust Units rather than settling the obligation with cash. The most restrictive term of the Convertible Debentures limits the issuance of additional Convertible Debentures if the principal amount of all issued and outstanding Convertible Debentures immediately after the issuance exceed 25% of the total market capitalization, being an aggregate of the principal amount of all issued and outstanding Convertible Debentures plus an amount equal to the current market price of all of the issued and outstanding Trust Units. At December 31, 2007, we would be limited to an additional issuance of Convertible Debentures of approximately $325 million.

Concurrent with the closing of the North Atlantic acquisition, North Atlantic entered into a Supply and Offtake Agreement with Vitol Refining S.A. (“Vitol”), a third party related to the vendor of North Atlantic. The agreement provides for ownership of substantially all of the crude oil feedstock and refined product inventory at the refinery be retained by Vitol and that Vitol be granted the right and obligation to provide and deliver crude oil feedstock to the refinery as well as the right and obligation to purchase all refined products produced by the refinery. For a more complete description of this Supply and Offtake Agreement, see the description of the Supply and Offtake Agreement in our Annual Information Form for the year ended December 31, 2007 to be filed on SEDAR at www.sedar.com. At the end of 2007, we estimate that Vitol held inventories of VGO, crude oil feedstock (both delivered and in-transit) and refined products for resale valued at approximately $818.1 million which would have otherwise been assets of Harvest.

During 2007, we issued a total of 26,194,998 Trust Units with 13,449,250 of those Trust Units issued in two public financings to raise $373.9 million at a weighted average price of $27.80 per Trust Unit, 5,922,708 Trust Units issued upon the conversion of Convertible Debentures, 6,809,987 Trust Units issued via a 29% level of participation in our distribution reinvestment programs and 13,053 Trust Units issued on the exercise of employee unit incentive plans. These issuances added $689.2 million to our equity bolstering our balance sheet ratios. In 2007, we have utilized our public financings to reduce bank borrowing incurred to fund the acquisition of North Atlantic in 2006 and Grand Petroleum in 2007 with the proceeds from the distribution reinvestment programs considered to be the balancing factor between our cash flow from operating activities, capital expenditure program and distributions.

During 2007, the trading value of our Trust Units ranged from a high of $34.97 in July to $19.75 in December. This volatility in our trading value is generally attributed to the seasonal fluctuation in refining margins and uncertainty created with the royalty review by the Province of Alberta offset by very strong crude oil prices. At the end of 2007 approximately 66% of our Unitholders were non-residents of Canada which is an increase from 54% at the end of 2006. We have experienced a reduction in the participation in our distribution reinvestment programs as the non-resident ownership of our Trust Units increases. We understand this is due to our Premium Distribution Re-investment Plan being very popular with our Unitholders resident in Canada. With the ownership of our Trust Units shifting to non-residents of Canada who are not eligible for the Premium Distribution Re-investment Plan, participation in our distribution reinvestment plans has diminished.

The following summarizes the trading value of our Trust Units during 2007 through to February 2008:

	Trading Price
Month	High		Low		Volume
TSX Trading
January 2007	$	26.22	$	23.20	12,822,502
February 2007	$	27.49	$	24.81	10,036,635
March 2007	$	29.22	$	25.90	11,430,584
April 2007	$	31.10	$	27.74	10,244,956
May 2007	$	33.16	$	30.25	13,984,905
June 2007	$	34.48	$	31.38	19,605,824
July 2007	$	34.97	$	29.50	19,478,671
August 2007	$	31.52	$	26.10	17,373,101
September 2007	$	29.40	$	25.18	15,463,720
October 2007	$	28.39	$	25.92	13,236,903
November 2007	$	26.99	$	20.42	12,281,080
December 2007	$	22.22	$	19.75	7,729,610
January 2008	$	23.56	$	20.48	10,474,631
February 2008	$	26.00	$	22.49	8,552,342

NYSE Trading (in US$)
January 2007	$	22.20	$	19.70	16,693,600
February 2007	$	23.55	$	21.18	10,059,454
March 2007	$	25.22	$	21.97	12,316,050
April 2007	$	28.07	$	24.00	10,038,123
May 2007	$	30.70	$	27.05	14,253,739
June 2007	$	32.46	$	29.47	13,474,838
July 2007	$	33.97	$	27.15	17,505,628
August 2007	$	29.74	$	24.29	23,146,747
September 2007	$	27.94	$	25.15	19,625,622
October 2007	$	29.11	$	25.94	20,887,843
November 2007	$	28.96	$	20.50	27,496,352
December 2007	$	22.20	$	19.80	18,794,208
January 2008	$	23.24	$	20.00	18,167,009
February 2008	$	25.70	$	22.51	15,108,961

We are authorized to issue an unlimited number of Trust Units and as of March 7, 2008, we had 150,580,097 Trust Units outstanding, 5,394,230 of Unit Appreciation Rights outstanding (of which 3,691,600 were vested) and 498,772 awards issued under the Unit Awards Incentive Plan (of which 278,463 were vested). In addition, we have six series of Convertible Debentures outstanding that are convertible into 19,633,017 Trust Units. Additionally one issue, $24,258,000 principal amount of 10.5% debentures, matured in January 2008 which we settled with the issuance of 1,116,593 Trust Units.

Effective June 22, 2007 with the enacting of Bill C-52, our future issuance of Trust Units and Convertible Debentures will be limited by the ”normal growth” guidelines contained therein. At the end of 2007, we estimate that we could issue approximately $550 million of Trust Units and Convertible Debentures in each of 2008, 2009 and 2010 with any unused “normal growth” available for use prior to 2011. In addition, we are entitled to issue approximately $590 million to replace debt held by the mutual fund trust on October 31, 2006. Trust Units issued pursuant to participation in our distribution reinvestment programs will be included as issuances in our “normal growth” limitation.

Through a combination of cash from operating activities, unused credit capacity and the working capital provided by the Supply and Offtake Agreement with Vitol, it is anticipated that we will have enough liquidity to fund future operations and forecasted capital expenditures although cash from operating activities used to fund ongoing operations may reduce the amount of future distributions paid to unitholders. At the end of 2007, our weighted average cost of capital, including our current level of distributions and the recent trading value of our Trust Units, is approximately 11.25%.

Distributions to Unitholders and Taxability

Harvest is an integrated energy trust with a declining asset base in our upstream operations and a “near perpetual” asset in our downstream operations. The future of our upstream operations relies on successful exploitation of our existing reserves, future development activities and strategic acquisitions to replace existing production and add additional reserves, as well as future petroleum and natural gas prices. With a prudent maintenance program, our downstream assets are expected to have a long life with additional growth in profitability available by upgrading the high sulphur fuel oil currently produced and/or expanding our refining capacity which is expected to provide favourable incremental economics from our existing infrastructure. Future development activities and modest acquisitions in our upstream business as well as the maintenance program in our downstream business will likely be funded by our cash generated from operating activities while we will generally rely on funding more significant acquisitions and growth initiatives from some combination of cash from operating activities, issuances of Trust Units and incremental debt. To the extent that we finance acquisitions and growth initiatives from cash from operating activities, the amount of our distributions to unitholders may be reduced. Should equity capital markets or incremental debt not be available to us, our ability to make the necessary expenditures to maintain or expand our assets may be impaired and result in reductions to future distributions paid to unitholders. 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. Accordingly, maintenance capital is not disclosed separately.

Our distributions will generally exceed the net income reported in our financial statements as a result of significant non-cash charges recorded in our income statement. In 2007, we recorded a $65.8 million charge in respect of future income tax expense and recognized a further $147.8 million in unrealized loss on price risk management contracts. In addition, we recorded a provision of $526.7 million in respect of depreciation and depletion which was based primarily on our historic costs of property, plant and equipment and does not accurately represent the fair value or replacement cost of the assets, nor do they affect cash generated in the current period. These charges result in significant changes to net income with no impact on cash from operating activities. Accordingly, we anticipate that over time our net income may fluctuate significantly from our cash flow from operating activities as well as distributions to unitholders. During 2007, our distributions to unitholders exceeded our net loss of $25.7 million by $636.0 million as compared to the prior year where our distributions to unitholders exceeded our net income of $136.0 million by $332.7 million. In instances where our distributions exceed our net earnings, a portion of the distribution may represent a return of capital rather than a distribution of earnings. During 2007, our distributions declared totaled $610.3 million, representing 95% of cash from operating activities.

Management, together with the Board of Directors of Harvest, continually assess the level of our monthly distributions in light of commodity price expectations, currency exchange rates, production and throughput projections, operating cost forecasts, debt leverage and spending plans. We maintained a monthly distribution of $0.38 per Trust Unit from February 2006 through October 2007 and commencing in November 2007, have declared a monthly distribution of $0.30 per Trust Unit through April 2008, a level of distributions that reflects our expectations of future commodity prices and currency exchange rates as well as our future production and throughput volumes and operating costs.

The following table summarizes the distributions declared, the proceeds from our distribution reinvestment programs as well as distributions as a percentage of cash from operating activities for the past two years:

	Year Ended December 31
(000s except per Trust Unit amounts)		2007		2006	Change
Distributions declared	$	610,280	$	468,787	30%
Per Trust Unit	$	4.40	$	4.53	(3%)
Distribution reinvestment proceeds	$	178,489	$	167,543	7%
Distributions as a percentage of cash from operating activities		95%		92%	3%

Throughout the first ten months of 2007, we declared monthly distributions of $0.38 per Trust Unit to Unitholders, and declared a monthly distribution of $0.30 per Trust Unit for the months of November and December 2007. The total distributions declared in 2007 was $610.3 million, which is 95% of our annual cash from operating activities. The $141.5 million increase in distributions declared during 2007 relative to 2006 is primarily due to the increase of approximately 26.2 million Trust Units outstanding following the acquisitions of Birchill and North Atlantic in 2006 along with issuance under our distribution re-investment plans and conversions of Convertible Debentures, offset by a reduction in the per unit amount of distributions declared in November and December of 2007.

Prior to January 1, 2011, the Trust is subject to tax on its taxable income less the portion that is paid or payable to the Unitholders at the end of each taxation year. For 2007 and 2006, our distributions to Unitholders were 100% taxable and the Trust had no taxable income.

OUTLOOK

Our 2008 business plan includes two significant changes as compared to our 2007 operating results. In 2008, our upstream operations will increase its focus on enhanced oil recovery and longer term value creation with capital spending of $225 million planned as compared to $300.7 million in 2007 and $376.9 million in 2006. In 2008, our enhanced oil recovery efforts will focus on fluid management projects in several of our larger oil reservoirs which we expect will ultimately reduce overall decline rates for an extended period due to improved oil recovery rates. The anticipated improved recoveries are based on maintenance of reservoir pressure and the bolstering of traditional waterflood projects with the introduction of proven chemical enhancements, such alkaline surfactant polymers. In our downstream operations, we are anticipating a robust year with no significant planned downtime for turnarounds and in the fourth quarter, an improved yield of gasoline and distillates attributed to an increase in the refinery’s visbreaking capacity.

Our 2008 capital spending focuses on drilling programs in southeast Saskatchewan, Lloydminister, Red Earth, Suffield and Hayter with approximately 120 wells anticipated accounting for approximately 65% of our 2008 capital budget. Our planned investment in infrastructure and workovers primarily relates to our reservoir management initiatives and will account for approximately twenty five percent of our 2008 spending including $8 million on the alkaline surfactant polymer project at Wainwright and a further $3 million investment in water handling capabilities at each of Bellshill Lake and Suffield to assist in re-pressurizing reservoirs. The balance of our capital program is allocated to projects necessary to maintain our existing infrastructure and does not increase production or reserves. The impact of an increased focus on reservoir management and reduced drilling activity results in a more stable production profile throughout the year as compared to a front-end loaded production profile attributed to flush production from first quarter drilling activity, particularly in Hay River. Currently, our 2008 capital spending plans have a moderate natural gas focus which could change with a relative improvement in the outlook for natural gas prices as compared to oil prices. Our more significant natural gas investments in 2008 will build on significant 2007 discoveries in west central Alberta and the addition of processing capacity at existing facilities.

We anticipate that our upstream production will average approximately 40,000 bbl/d of liquids and 93,000 mcf/d of natural gas with a moderate declining production profile throughout the year. We anticipate production will be slightly front-end loaded in the first quarter due to drilling in southeast Saskatchewan and the tie-in of approximately 1,000 bbl/d of production from our 2007 drilling program. Light and medium gravity oil, including natural gas liquids, is expected to represent approximately 49% of our total production in 2008 with heavy oil and natural gas accounting for 23% and 28% respectively. We expect operating costs will continue to be a challenge in 2008 with approximately 40% of our costs attributed to electric power and well servicing. Power costs are significant for us as we move and dispose of approximately 2 million bbl/d of water to produce 40,000 bbl/d of oil and these costs will likely increase as we enhance our reservoir management focus. For 2008, we are projecting our operating costs to be approximately $13.00 per boe as compared to $13.66 in 2007 while our 2008 general and administrative costs are expected to average about $1.40 per boe.

In our downstream operations, we are not anticipating any planned shutdowns except for the shutdown of the visbreaker to enable the commissioning of our visbreaker upgrading project, and accordingly, are anticipating a 12% increase in throughput in 2008 to 112,900 bbl/d of feedstock. In 2007, we completed a turnaround of the crude vacuum units with the expectation that our purchases of vacuum gas oil from third parties would be reduced. For 2008, we anticipate a 4,800 bbl/d reduction in vacuum gas oil purchases at a cost saving of approximately $40 million. Currently, we expect that our operating costs and purchased energy costs will aggregate to $4.75 per bbl of throughput including the impact of recently re-negotiated labour contract and a Canadian dollar at parity with the US dollar. We are also concentrating on capturing $10 million of operating cost reductions by improving energy efficiency and other operating measures which could reduce unit operating costs by $0.25 per barrel. Capital spending in our downstream operations is expected to total $63 million comprised of $22 million of mandatory/maintenance projects, $13 million discretionary projects, $25 million to complete the visbreaker project and $3 million on planning longer range refinery development projects. The cash flow contribution from our retail and wholesale marketing activities in the Province of Newfoundland and Labrador is expected to continue to add approximately $20 million of incremental cash flow to the downstream operations.

As discussed in the Cash Flow Risk Management section of this MD&A, we have refined product and WTI pricing contracts that represent approximately 79% of our cash flow exposure in the first half of 2008, 68% for the second half of 2008 and 53% for the first half of 2009. With respect to our cash flow exposure related to refined product crack spreads, we have contracts in place for approximately 10% of our 2008 exposure. We also have a modest 276 GJ/d of natural gas fixed price contracts in place. Although, we may enjoy unprecedented crude oil prices in 2008, our upside participation will be limited to an average WTI price of US$78.81/bbl within our 20,000 bbl/d of heating oil and fuel oil price risk management contracts. We have currency exchange contracts on US$18.3 million per month through to June 2008 with an average exchange rate of US$0.93 and an additional US$10.0 million per month through to December 2008 with an average exchange rate of US$0.95 representing approximately 20% of our exposure to fluctuations in the US dollar to Canadian dollar exchange rate, prior to considering the offsetting exposure of our US dollar denominated 7^7/8% Senior Notes. We have also entered into contracts to fix the price of 35 MWh through to the end of December 2008 at price of $56.69 with the objective of reducing the volatility of our operating costs to fluctuating electricity costs which represent approximately 20% of our upstream operating costs.

We manage our exposure to fluctuations in interest rates by maintaining a mix of short and longer term financing with the short term financing typically carrying floating interest rates and longer term financing (our 7^7/8% Senior Notes and Convertible Debentures) carrying fixed rates of interest. Our short term financing consists of borrowings under our credit facilities, $1,279.5 million at December 31, 2007, which represent approximately 60% of our total debt. Accordingly, approximately 60% of our interest rate exposure is floating and 40% is fixed. Currently, our most significant exposure to increasing interest rates is through the re-pricing of credit as we extend (or renew) our credit facilities or enter into additional longer term financings. Prior to mid-2007, our short term interest rate was approximately 70 basis points over Bankers Acceptance rates while our long term rates based on the trading price of our 7^7/8% Senior Notes was 250 basis points over the ten year US Treasury Bonds. As discussed in the Liquidity and Capital Resources section of this MD&A we may defer our credit facility extension request. With respect to further reducing our borrowings under this credit facility, we continue to monitor the high yield market as well as opportunities to issue additional Convertible Debentures and Trust Units.

On January 31, 2008, approximately $24.3 million of principal amount 10.5% Convertible Debentures matured and we elected to satisfy this obligation by issuing 1,116,593 Trust Units rather than settling the obligations in cash. This same option is available on all of the $666.9 million of principal amount of Convertible Debentures issued in six series with maturities in 2009, 2010, 2012, 2013 and 2014 as to $2.7 million, $37.1 million, $174.6 million, $379.3 million and $73.2 million, respectively. While not necessarily impacting 2008, we anticipate that as these Convertible Debentures mature, or are converted into Trust Units before their maturity date, we will be able to retire $666.9 million of principal amount of unsecured debt with equity issuances.

Overall, we expect that based on current commodity price expectations, our 2008 cash from operating activities will be sufficient to fund our planned capital expenditures as well as maintain our present level of distributions. In prior years, we have balanced our cash from operating activities and the funding of capital expenditures and distributions with reliance on proceeds from our distribution re-investment programs for shortfalls. The participation level in our distribution re-investment programs was 38% in 2006. However, as the ownership of our Trust Units by non-Canadian residents increased in 2007, the participation in our Premium Distribution Re-investment Plan^TM has steadily diminished as non-residents of Canada do not qualify for this program which accounts for a substantial portion of the funding from our distribution re-investment programs. As of December 31, 2007, we estimate that 66% of our Unitholders are non-Canadian residents, a significant increase from 54% at the end of 2006 and 33% in February 2006 when Harvest and Viking merged.

While we do not forecast commodity prices nor refining margins, we have entered into price risk management contracts to mitigate a substantial portion of our price volatility with the objective of stabilizing our 2008 cash flow from operating activities through a wide variety of pricing environments. The following table reflects the sensitivity of our 2008 operations to changes in the following key factors to our business including the impact of our price risk management contracts:

		Assumption		Change	Impact on Cash Flow
WTI oil price (US$/bbl)	$	90.00	$	5.00	$	0.18 / Unit
CAD/USD exchange rate	$	1.00	$	0.05	$	0.36 / Unit
AECO daily natural gas price	$	7.00	$	1.00	$	0.19 / Unit
Refinery crack spread (US$/bbl)	$	9.00	$	1.00	$	0.27 / Unit
Upstream Operating Expenses (per boe)	$	12.90	$	1.00	$	0.14 / Unit

In our upstream business, we will continue to evaluate opportunities to acquire producing oil and/or natural gas properties as well as offer selected properties for divestment while striving to maintain or enhance our productive capability and improve our unit operating costs. In addition, we intend to be an active participant in the consolidation of the Canadian energy industry, including royalty trusts.

In our downstream business, we are currently evaluating several opportunities to expand and/or reconfigure the refinery and have engaged SNC Lavalin to review the technical and economic feasibility of these options. The options include a project to convert approximately 30,000 bbl/d of high sulphur fuel oil to higher valued refined products, expand processing capacity supported by existing infrastructure and enhancing capability to refine a heavier and lower cost crude feedstock to improve margins. SNC Lavalin is expected to complete its study and provide its report by June 2008. With approval to proceed dependent on the outlook on worldwide growth in refining capacity, an expansion could boost throughput capacity and may take three to five years to complete. With costs expected to exceed $1 billion, we could either use our capital or a tolling processing arrangement from a producer seeking captive refining capacity to process its crude oil. There are also economic gains to be had by upgrading our combustion technologies.

The changes to Canada’s Income Tax Act to apply a tax on distributions from publicly traded mutual fund trusts, including Harvest, have now been enacted with an effective date of January 1, 2011. We continue to search and validate various capital structures, balancing the benefits of the remaining years of tax efficient distributions against the longer term benefits of continuing with a growth strategy beyond the announced “normal growth” limitations. On December 14, 2007, Bill C-28 implemented reductions in the federal corporate income tax rates which will also apply to the tax on distributions from publicly traded mutual fund trusts. See the Future Income Tax section in this MD&A for a more detailed discussion.

SUMMARY OF FOURTH QUARTER RESULTS

	Three months ended December 31
		2007			2006
	Upstream	Downstream	Total	Upstream	Downstream	Total	Change

Revenues	308,022	624,512	932,534	273,110	460,359	733,469	27%
Royalties	(53,410)	-	(53,410)	(50,725)	-	(50,725)	5%
Net revenues	254,612	624,512	879,124	222,385	460,359	682,744	29%

Purchased product for resale and processing	-	579,765	579,765	-	386,014	386,014	50%
Operating expenses	76,100	81,271	157,371	69,298	34,063	103,361	52%

General and administrative expenses	7,979	441	8,420	6,714	-	6,714	25%
Less: Unit based compensation expenses	(3,688)	48	(3,640)	(167)	-	(167)	2080%
Total cash general and administrative expenses	4,291	489	4,780	6,547	-	6,547	(27%)

Transportation and marketing	2,347	7,895	10,242	2,919	5,060	7,979	28%
Depreciation, depletion and accretion	115,176	17,746	132,922	116,262	15,482	131,744	1%
Net income per segment	56,698	(62,654)	(5,956)	27,359	19,740	47,099	(113%)

Realized losses (gains) on risk management contracts			17,375			5,996	190%
Unrealized losses (gains) on risk management contracts			122,739			(16,213)	857%
Interest and other financing charges			36,959			41,184	(10%)
Corporate costs⁽²⁾			(69,444)			14,599	(576%)
Net (loss) income			(113,585)			1,533	(7509%)
Per Trust Unit, basic			(0.77)			0.01	(7800%)
Per Trust Unit, diluted			(0.77)			0.01	(7800%)

Cash From Operating Activities			87,998			140,543	37%
Per Trust Unit, basic			0.60			1.21	(50%)
Per Trust Unit, diluted			0.60			1.16	(48%)

Distributions declared			144,681			134,974	(7%)
Distributions declared, per Trust Unit			0.98			1.14	(14%)
Distributions declared as a percentage of Cash			164%			96%	68%
From Operations

UPSTREAM OPERATIONS
Daily Production
Light / medium oil (bbl/d)			26,640			28,152	(5%)
Heavy oil (bbl/d)			13,354			13,967	(4%)
Natural gas liquids (bbl/d)			2,595			2,649	(2%)
Natural gas (mcf/d)			94,961			112,006	(15%)
Total daily sales volume (boe/d)			58,416			63,436	(8%)

Operating Netback⁽¹⁾ ($/BOE)
Revenue			57.32			46.80	22%
Royalties as percent of revenue			(9.94)			(8.69)	14%
Operating expense			(14.16)			(11.87)	19%
Transportation expense			(0.44)			(0.50)	(12%)
Operating Netback⁽¹⁾			32.78			25.74	27%

Cash capital expenditures			30,643			90,358	(66%)

DOWNSTREAM OPERATIONS⁽³⁾
Average daily throughput (bbl/d)			61,717			86,890	(29%)
Aggregate throughput (mbbl)			5,678			6,343	(10%)
Average Refining Margin (US$/bbl)			6.00			9.32	(36%)
Cash capital expenditures			16,889			21,411	(21%)

⁽¹⁾

This is a non-GAAP measure, please refer to “Non-GAAP Measure” in this MD&A.

⁽²⁾

Includes foreign exchange losses, taxes and amounts realized on the series of US dollar forward purchase contracts entered into with respect to the purchase of North Atlantic

⁽³⁾

Downstream operations acquired on October 19, 2006.

Our 2007 fourth quarter results are not directly comparable to our 2006 fourth quarter results due to the acquisition of the North Atlantic during the fourth quarter of 2006, the turnaround activity at the refinery in the fourth quarter of both 2007 and 2006, and the acquisition of Grand Petroleum in the third quarter of 2007.

Upstream Operations

Our 2007 fourth quarter revenues increased $34.9 million over the same period in the prior year as a result of our realized commodity prices increasing by $10.52/boe (22%) due to significantly higher crude oil prices. Offsetting the increase in our realized commodity prices in the fourth quarter is a decrease in production volumes of 5,020 boe/d as compared to the prior period due to normal decline on our crude oil and natural gas production. Light / medium oil sales revenue for the three month period ended December 31, 2007 was $34.1 million (or 24%) higher than in same period in the prior year due to a favourable price variance of $41.6 million and an unfavourable volume variance of $7.5 million. Heavy oil revenues for the three months ended December 31, 2007 increased by $11.7 million (or 24%) due to a favourable price variance of $13.8 million and an unfavourable volume variance of $2.1 million. Natural gas sales revenue decreased by $15.9 million (or 22%) for the three months ended December 31, 2007 over the same period in 2006, which reflects an unfavourable price variance of $4.9 million and an unfavourable volume variance of $11.0 million.

For the three months ended December 31, 2007, our net royalties as a percentage of revenue were 17.3% ($53.4 million) as compared to 18.6% ($50.7 million) in the same period in 2006. The decrease in the royalty rate is mainly due to receiving crown royalty refunds on some of our shut in gas-over-bitumen production in the fourth quarter of 2007.

Operating expenses increased by $6.8 million (or 10%) for the three months ended December 31, 2007 compared to the same period in the prior year which reflects cost pressures in the western Canadian oil and natural gas sector.

For the three months ended December 31, 2007, Cash G&A increased by $1.3 million (or 19%) compared to the same period in the prior year. This increase is reflective of additional costs relating to consultant fees and generally higher costs to retain technically qualified staff in the western Canadian petroleum and natural gas industry.

After capital spending of $148.5 million, $48.2 million, and $73.3 million in the first, second and third quarters of 2007, respectively, capital spending in our upstream segment in the fourth quarter totaled $30.6 million which was mainly focused on tying-in our drilling results.

Downstream Operations

Our fourth quarter 2007 downstream operating results are not very comparable with the same period in the prior year, as the refinery was acquired midway through the fourth quarter of 2006 and during both periods the refinery undertook significant turnaround activity. Our operating results in the fourth quarter of 2007 reflect the impact of two planned shutdowns and weaker refining margins relative to the first and second quarters of 2007. By early December 2007, the refinery had returned to full operations with throughput averaging 109,611 bbl/d. For the fourth quarter 2006, our results reflect the impact of an extended turnaround commencing October 1, 2006 with the refinery returning to full operations near the end of November 2006 only to experience additional downtime in December 2006 due to a pipe rupture and a disruption in electric power service.

Corporate

Interest expense decreased by $4.2 million for the three months ended December 31, 2007 relative to the same period in the prior year due to a decrease in our total debt outstanding as a result of the issuance of $230.0 million of principal amount of Convertible Debentures and 13,499,250 Trust Units for total net proceeds of $576.0 million in the first half of 2007.

In the fourth quarter of 2007 we realized a $17.4 million loss and a $122.7 million unrealized loss on our risk management contracts as compared to a realized loss of $6.0 million and a $16.2 million unrealized gain in the same period in 2006. The significant unrealized loss in the fourth quarter of 2007 is due to our refined products and WTI price contracts as the refined product contracts were placed in mid-2007 when the WTI benchmark price was approximately US$71.00 and the NYMEX price for heating oil and Platts Index for fuel oil were approximately US$2.00 per gallon and US$55.00 per barrel, respectively, as compared to the 2007 year end closing prices of US$95.98 for WTI, US$2.64 per gallon for NYMEX heating oil and US$75.15 per barrel for Platts fuel oil

SUMMARY OF QUARTERLY RESULTS

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

		2007								2006
(000s except where noted)		Q4		Q3		Q2	Q1			Q4		Q3		Q2		Q1
Revenue, net of royalties	$	879,124	$	1,007,786	$	1,133,450	$	1,025,512	$	682,744	$	259,818	$	257,103	$	181,160

Net income (loss)	$	(113,585)	$	11,811	$	6,248	$	69,850	$	1,533	$	107,768	$	60,682	$	(33,937)
Per Trust Unit, basic⁽¹⁾	$	(0.77)	$	0.08	$	0.05	$	0.55	$	0.01	$	1.01	$	0.60	$	(0.41)
Per Trust Unit, diluted¹	$	(0.77)	$	0.08	$	0.05	$	0.55	$	0.01	$	0.99	$	0.60	$	(0.41)

Cash from operating activities	$	87,998	$	191,049	$	251,218	$	111,048	$	140,543	$	143,597	$	135,581	$	88,164
Per Trust Unit, basic	$	0.60	$	1.31	$	1.88	$	0.87	$	1.21	$	1.35	$	1.34	$	1.07
Per Trust Unit, diluted	$	0.60	$	1.22	$	1.67	$	0.84	$	1.16	$	1.31	$	1.30	$	1.07

Distributions per Unit, declared	$	0.98	$	1.14	$	1.14	$	1.14	$	1.14	$	1.14	$	1.14	$	1.11

Total long term financial liabilities	$	2,172,417	$	2,072,870	$	1,961,748	$	2,409,241	$	2,488,524	$	1,105,728	$	746,840	$	735,896
Total assets	$	5,451,683	$	5,585,651	$	5,613,333	$	5,800,346	$	5,745,558	$	4,076,771	$	3,455,918	$	3,470,653

⁽¹⁾ The sum of the interim periods does not equal the total per year amount as there were large fluctuations in the weighted average number of Trust Units outstanding in each individual quarter.

Net revenues have generally increased steadily over the eight quarters with significantly higher revenue in the Second and Third Quarters of 2006 over the preceding quarters due to the incremental revenue from the Viking acquisition in February 2006 along with stronger commodity prices including narrowing crude oil differentials. In the Fourth Quarter of 2006, the significant increase in revenue over the prior quarter is attributed to the North Atlantic acquisition which is a margin business with significant revenues coupled with significant costs for crude oil feedstock. In the second half of 2007 net revenues decreased from the first half of 2007 due to the Refinery’s lower realized prices and decreased throughput due to two planned shutdowns. The growth in cash from operating activities is closely aligned with the growth in net revenues and is attributed to the same factors as the growth in net revenues, reflecting the cyclical nature of the downstream segment in 2007.

Net income reflects both cash and non-cash items. Changes in non-cash items, including future income tax, DDA&A expense, unrealized foreign exchange gains and losses, unrealized gains and losses on risk management contracts and Trust Unit right compensation expense cause net income to vary significantly from period to period. In the Second Quarter of 2007 Bill C-52 was substantively enacted, which imposed a new tax on distributions from publicly traded income trusts resulting in a large future income tax expense in the quarter. In the Fourth Quarter of 2007 Bill C-28 implemented reductions in the federal corporate income tax rates which will also apply to the tax on distributions from publicly traded mutual fund trusts, resulting in a significant future income tax recover in the quarter. Additionally, the volatility in net income (loss) between quarters in 2006 and 2007 is due to the changes in the fair value of our risk management contracts and this is the primary reason why our net income (loss) does not reflect the same trends as net revenues or cash from operating activities.

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

CRITICAL ACCOUNTING ESTIMATES

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

Reserves

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

Expected reservoir characteristics based on geological, geophysical and engineering assessments;
Future production rates based on historical performance and expected future operating and investment activities;
Future oil and gas prices and quality differentials; and
Future development costs.

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

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

Asset Retirement Obligations

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

Impairment of Capital Assets

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 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. 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 20%, 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 25%, 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.

Any impairment charges would reduce our net income.

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

Goodwill

Goodwill is recorded on a business combination when the total purchase consideration exceeds the fair value of the net identifiable assets and liabilities of the acquired entity. The goodwill balance is not amortized, however, must be assessed for impairment at least annually. Impairment is initially determined based on the fair value of a reporting unit compared to its book value. Any impairment must be charged to earnings in the period the impairment occurs. Harvest has a goodwill balance for each of our upstream and downstream operations. As at December 31, 2007, we have determined there was no goodwill impairment in either of our reporting units.

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 2007 (0.5% in 2006).

Purchase Price Allocations

Business acquisitions are accounted for by the purchase method of accounting. Under this method, the purchase price is allocated to the assets acquired and the liabilities assumed based on the fair values at the time of the acquisitions. The excess of the purchase price over the assigned fair values of the identifiable assets and liabilities is allocated to goodwill. In determining the fair value of the assets and liabilities we are often required to make assumptions and estimates about future events, such as future oil and gas prices, 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.

RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

Convergence of Canadian GAAP with International Financial Reporting Standards

In early 2007, Canada’s Accounting Standards Board (“AcSB”) issued a decision summary with respect to a previously issued strategic plan that will result in Canadian GAAP, as used by public companies, being converged with International Financial Reporting Standards (“IFRS”). In early 2008, it was confirmed by the AcSB that the transitions date from Canadian GAAP to IFRS will be January 1, 2011. We are currently evaluating our options with respect to this change and accordingly it is premature to assess the impact of the initiative, if any, on our financial statements at this time.

Financial Instruments – Disclosures and Presentation

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

Section 3862 – Financial Instruments – Disclosures

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

Section 3863 – Financial Instruments – Presentation

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

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

In June 2007, the AcSB issued section 3031, Inventories, which replaces the existing inventories standard. This new standard provides additional guidance with respect to the measurement and disclosure requirements for inventories, requiring inventories to be valued at the lower of cost and net realizable value. This standard is to be adopted for fiscal years beginning on or after January 1, 2008. We do not expect the adoption of this section to have a material impact on our net income or financial position.

In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets, replacing Section 3062 Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs. The new Section will be effective on January 1, 2009. Section 3062 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. We are currently evaluating the impact of the adoption of this new Section, however do not expect a material impact on our Consolidated Financial Statements.

OPERATIONAL AND OTHER BUSINESS RISKS

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

The following summarizes the more significant risks of our upstream and downstream operations. See our Annual Information Form for a full description of these risks as well as risks associated with our royalty trust structure.

Operation of oil and natural gas properties:

Applying a proactive management approach to our properties;
Selectively adding skilled and experienced employees and providing encouragement and opportunities to maintain and improve technical competence; and

Operation of a refining and petroleum marketing business

Maintaining a proactive approach to managing the supply of feedstock and sale of refined products (including the Supply and Offtake Agreement with Vitol Refining S.A.) to ensure the continuity of supply of crude oil to the refinery and the delivery of refined products from the refinery;
Allocating sufficient resources to ensure good relations are maintained with our non-unionized and unionized work force; and
Selectively adding experienced refining management to further strengthen our “in-house” management team.

Estimates of the quantity of recoverable reserves:

Acquiring oil and natural gas properties that have high-quality reservoirs combined with mature, predictable and reliable production and thus reduce technical uncertainty;
Subjecting all property acquisitions to rigorous operational, geological, financial and environmental review; and
Pursuing a capital expenditure program to reduce production decline rates, improve operating efficiency and increase ultimate recovery of the resource-in-place.

Commodity price exposures:

Maintaining a risk-management policy and committee to continuously review effectiveness of existing actions, identify new or developing issues and devise and recommend to the Board of Directors of Harvest Operations action to be taken;
Executing risk management contracts with a portfolio of credit-worthy counterparties;
Maintaining an efficient cost structure to maximize product netbacks; and
Limiting the period of exposure to price fluctuations between crude oil prices and product prices by entering into contracts such that crude oil feedstock will be priced based on the price at or near the time of delivery to the refinery, which may be as much as 24 days subsequent to the time the feedstock is initially loaded onto the shipping vessel. Thereby, minimizing the time between the pricing of the feedstock and the refined products with the objective of maintaining margins.

Financial risk:

Monitoring financial markets to ensure the cost of debt and equity capital is kept as low as reasonably possible;
Retaining a portion of cash flows to finance capital expenditures and future property acquisitions; and
Carrying adequate insurance to cover property and business interruption losses.

Environmental, health and safety risks:

Adhering to our safety programs and keeping abreast of current industry practices for both the oil and natural gas industry as well as the refining industry; and
Committing funds on an ongoing basis toward the remediation of potential environmental issues.

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

Retaining an experienced, diverse and actively involved Board of Directors to ensure good corporate governance; and
Engaging technical specialists when necessary to advise and assist with the implementation of policies and procedures to assist in dealing with the changing regulatory environment.

CHANGES IN REGULATORY ENVIRONMENT

On October 25, 2007, the Government of Alberta released its New Royalty Framework outlining changes that effective January 1, 2009 will increase the royalty rates on conventional oil and gas, oil sands and coalbed methane using a price-sensitive and volume-sensitive sliding rate formula for both conventional oil and natural gas. While there are considerable details to be provided, our preliminary assessment is that the impact of the changes on Harvest will be modest, as many of our oil and natural gas wells will be considered low productivity wells that continue to attract favourable royalty treatment. Based on the information available and assuming royalties will continue to be based on field gate prices realized by producers, our analysis indicates that if our field gate prices are less than $53.00, our oil royalties will be lower and if prices are higher, our royalties will increase and similarly for natural gas, if our gas plant prices are less than $7.00, our royalties will be lower and if prices are higher, our royalties will increase. Of particular concern is the royalty rates on natural gas where production from recently drilled wells may qualify as high productivity for a period of time and attract a royalty that is 15% to 20% higher than under the current royalty regime and this could significantly penalize the economics of our drilling and natural gas wells. Generally, we will pay higher royalties if commodity prices are high and lower royalties on most of our wells as they will be considered to be low productivity wells.

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.

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.

NON-GAAP MEASURES

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

Disclosure Controls and Procedures and Internal Control over Financial Reporting

Under the supervision of our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2007 as defined under the rules adopted by the Canadian securities regulatory authorities and the US Securities and Exchange Commission. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2007, our disclosure controls and procedures were effective to ensure that information required to be disclosed by Harvest in reports it files or submits to Canadian and US securities authorities was recorded, processed, summarized and reported within the time period specified in Canadian and US securities laws and was accumulated and communicated to Harvest’s management, including its Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.

Management is responsible for establishing and maintaining internal control over our financial reporting. Our internal control is 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, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated in the effectiveness of our internal control over financial reporting as of December 31, 2007. 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 has concluded that as of December 31, 2007, we had effective internal control over financial reporting.

The effectiveness of our internal control over financial reporting as of December 31, 2007 was audited by KPMG, an independent registered public accounting firm, as stated in their report, which is included in our audited consolidated financial statements for the year ended December 31, 2007.

During the year ended December 31, 2007, 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 except for the appointment of a Chief Operating Officer – Downstream. The appointment enhanced our oversight of these operations.

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 now well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control systems are met.

ADDITIONAL INFORMATION

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

Harvest Energy Trust (HTE) Inactive 6-KHarvest Energy Announces Fourth Quarter and Full Year 2007 Results and Distribution Declaration