Harvest Energy Trust 6K Current report | HTE 23 Mar 07

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s discussion and analysis ("MD&A") of the financial condition and results of operations of Harvest Energy Trust should be read in conjunction with our audited consolidated financial statements and accompanying notes for the years ended December 31, 2006 and 2005. 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. The information and opinions concerning our future outlook are based on information available at March 12, 2006.

When reviewing our 2006 results and comparing them to 2005, readers should be cognizant that the 2006 results include a full year of operations from our Hay River acquisition in August 2005, eleven months of operations from our acquisition of Viking Energy Royalty Trust ("Viking") in February 2006, and five months of operations from the Birchill Energy Limited ("Birchill") acquisition in August 2006. In addition, on October 19, 2006, we acquired North Atlantic Refining Ltd.("North Atlantic") and our 2006 results include North Atlantic operations from the date of acquisition. The combination of these events significantly impacts the comparability of our operations and financial results for 2006 to the results of 2005.

All references are to Canadian dollars unless otherwise indicated. Tabular amounts are in thousands of dollars unless otherwise stated. Natural gas volumes are converted to barrels of oil equivalent ("boe") using the ratio of six thousand cubic feet ("6 mcf") of natural gas to one (1) barrel of oil ("bbl"). Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.

In accordance with Canadian practice, production volumes, reserve volumes and revenues are reported on a gross basis, before deduction of crown and other royalties, unless otherwise stated.

We use certain financial reporting measures that are commonly used as benchmarks within the oil and natural gas industry in the following MD&A such as Cash Flow, Payout Ratio, Cash General and Administrative Expenses and Operating Netbacks and with respect to the refining industry, Gross Margin, and Operating Income (calculation tables within the MD&A) each as 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 company or trust. When these measures are used, they are defined as "non-GAAP" and should be given careful consideration by the reader. Please refer to the discussion under the heading "Non-GAAP Measures" at the end of this MD&A for a detailed discussion of these reporting measures.

2006 Consolidated Financial and Operating Highlights

Cash Flows of $551.7 million for the year ended December 31, 2006 with production of 59,729 boe/d, an increase of $241.9 million and 23,158 boe/d over the prior year, respectively, primarily due to continued strength in oil prices, and the acquisition of Viking in February 2006 and Birchill in August 2006.

Acquisition of North Atlantic Refining Ltd. for cash consideration of $1.6 billion on October 19, 2006 resulting in the addition of a 115,000 bbl/d medium gravity sour refinery to our petroleum and natural gas operations in Western Canada.

Completed a $376.9 million capital program in Western Canada resulting in 252 gross petroleum and natural gas wells drilled with a success rate of 98% and incremental reserves replacing approximately 87% of 2006 production (prior to the conversion of previously booked undeveloped reserves) as well as an exit production rate at the end of the year of 65,023 boe/d.

Maintained our monthly distributions at $0.38 per trust unit per month through the year resulting in a Payout Ratio of 85%.

Established revolving credit facilities totaling $1.4 billion on a secured covenant based agreement with a three year extendable term as well as established an incremental $800 million of bridge facilities for the North Atlantic acquisition which have now been fully repaid.

Raised $1.2 billion with the issuance of 22,672,250 trust units and $609.5 million principal amount of convertible debentures including the offering closed in February 2007.

Fourth quarter Cash Flows of $156.3 million with a payout ratio of 86%.

SELECTED ANNUAL INFORMATION

The table below provides a summary of our financial and operating results for the twelve month periods ended December 31, 2006, December 31, 2005 and December 31, 2004. Detailed commentary on individual items within this table is provided elsewhere in this MD&A.

	Year ended December 31

($000s except where noted)							Change 2006
		2006		2005		2004	to 2005
Revenue, net⁽¹⁾	1,388,196			436,452		212,118	218%

Cash Flow⁽²⁾		551,724		309,843		123,710	78%
Per trust unit, basic⁽²⁾	$	5.43	$	6.66	$	4.94	(18%)
Per trust unit, diluted⁽²⁾	$	5.24	$	6.35	$	3.97	(17%)

Net income (loss)		136,046		104,946		11,241	30%
Per trust unit, basic	$	1.34	$	2.25	$	0.45	(40%)
Per trust unit, diluted	$	1.33	$	2.19	$	0.43	(39%)

Distributions declared		468,787		153,494		64,563	205%
Distributions declared, per trust unit	$	4.53	$	3.20	$	2.40	42%
Payout ratio ⁽²⁾⁽³⁾		85%		50%		52%	35%

Bank debt	1,595,663			13,869		75,519	11,405%
Senior debt		291,350		290,750		300,500	-
Convertible Debentures		601,511		44,455		25,750	1253%
Total long-term financial liabilities	2,488,524			349,074		401,769	613%

Total assets	5,745,558		1,308,481			1,050,483	339%

PETROLEUM AND NATURAL GAS OPERATIONS

Daily Production
Light to medium oil (bbl/d)		27,482		17,590		12,336	56%
Heavy oil (bbl/d)		13,904		13,747		8,495	1%
Natural gas liquids (bbl/d)		2,247		824		472	173%
Natural gas (mcf/d)		96,578		26,461		10,999	265%
Total daily sales volumes (boe/day)		59,729		36,571		23,136	63%

Cash capital expenditures		376,881		120,508		42,662	213%

	As at December 31, 2006				As at December 31, 2005

Reserves (mBOE), based on Forecast prices and costs		Gross		Net		Gross	Net
Proved reserves		159,235	137,663			87,731	77,567
Probable reserves		61,036	52,231			31,946	27,984
Total proved plus probable (P+P) reserves		220,271	189,894			119,677	105,551


REFINING AND MARKETING OPERATIONS
(from October 19, 2006 the date of acquisition to December 31, 2006)

Average daily throughput (bbl/d)	86,890	-	-	n/a
Aggregate throughput (mbbl)	6,343	-	-	n/a

Cash capital expenditures	21,411	-	-	n/a

(1) Revenues are net of royalties and risk management activities
(2) These are non-GAAP measures; please refer to "Non-GAAP Measures" in this MD&A.
(3) Ratio of distributions declared to Cash Flows, excluding special distribution of $10.7 million settled with the issuance of trust units in 2005.

OVERALL PERFORMANCE

Subsequent to our acquisition of North Atlantic, Harvest is a fully integrated energy trust. Our petroleum and natural gas business is focused on the operation and development of quality properties in western Canada. We employ a disciplined approach to the oil and natural gas business, whereby we acquire high working interest, large resource-in-place, stable producing properties and employ "best practice" technical and field operational processes to extract maximum value. These operational processes include: diligent hands-on management to maintain and maximize production rates, the application of technology and selective capital investment to maximize reservoir recovery, and the enhancement of operational efficiencies to control and reduce expenses. Our refining and marketing business is focused on the efficient operation of a medium gravity, sour crude hydrocracking refinery and a petroleum marketing business both located in the Province of Newfoundland and Labrador. We were attracted to this asset because of its low Cash Flow multiple and relatively low level of annual capital reinvestment required relative to our petroleum and natural gas business.

We generated Cash Flows of $551.7 million ($5.43 per basic trust unit) with petroleum and natural gas production of 59,729 boe/d in the year ended December 31, 2006, compared to Cash Flows of $309.8 million ($6.66 per basic trust unit) and production of 36,571 boe/d in 2005. This $241.9 million increase in Cash Flow is substantially attributed to the incremental impact of the Viking acquisition on our Cash Flows and to a lesser degree, the impact of the Birchill and North Atlantic acquisition. In addition, the continued strong crude oil and heavy oil differential pricing environment positively impacted our Cash Flows during the year, offsetting relative weakness in natural gas prices.

We are vulnerable to the price differentials between Edmonton Par and Bow River as our production is approximately 23% weighted towards heavy oil, which is priced off of the Bow River Stream and a portion of our light/medium production is also priced off of the Bow River Stream. For the year ended December 31, 2006 compared to December 31, 2005, heavy oil differentials were narrower overall and this is reflected in our Cash Flows. With the acquisition of the North Atlantic refinery, which processes medium gravity crude oil, our exposure to wide differentials is somewhat mitigated as our Cash Flows from the refinery are stronger when heavy oil differentials are wider. However, these positive changes to our Cash Flows have been partially offset by the rising cost pressures in the petroleum and natural gas service sector.

Production increases over the prior year are primarily attributed to the acquisitions made during 2006 as well as our successful development drilling program. These increases were offset by several production disruptions during the year: in Markerville, where approximately 3,500 boe/d of production was shut-in for the month of July and the first week of August following a fire at a non-operated gas processing facility; in Hay River, where production was impacted by first quarter maintenance turnarounds and our drilling program and in the fourth quarter due to a temporary shutdown of Rainbow pipeline; and, in Bellshill, where power disruptions impacted production. However, despite the production challenges experienced during the year we were able to exit 2006 with an average production of 65,023 boe/d. Our fourth quarter 2006 production volumes were 63,436 boe/d, compared to 38,834 boe/d in the fourth quarter of 2005, an increase of 63% attributed to acquisitions made during 2006 and our drilling program, partially offset by the shutdown of the Rainbow pipeline.

Distributions declared during the year totaled $4.53 per trust unit, for a payout ratio of 85%. Annual distributions declared were $1.33 per trust unit (or 42%) higher than those declared in the prior year, when the payout ratio was 50%. For the year ended December 31, 2006 the participation in our distribution reinvestment plan was approximately 38% while for the year ended December 31, 2005 the Distribution Reinvestment Plan ("DRIP") participation was 25%. Our DRIP plan enables us to settle our distributions through the issue of units and allows us to use the cash to reinvest in our capital program or for debt repayment. With potential increases in Cash Flow in 2007 due to the acquisition of the refinery and the increase of the floor prices of a number of price risk management contracts in 2007 and assuming a $0.38 per trust unit monthly distribution level, we anticipate a reduction in our 2007 payout ratio.

On February 3, 2006, Viking was acquired with the issuance of 46,040,788 trust units to former Viking unit holders, the assumption of Viking’s 10.5% and 6.40% unsecured subordinated convertible debentures with an aggregate face value of $210 million and the assumption of $106.2 million of bank debt resulting in an aggregate consideration of $1,975.3 million including acquisition costs. This acquisition provided us with an improved product mix, more weighted towards light/medium crude oil and natural gas and less weighted towards heavy oil. Concurrent with the acquisition of Viking, we negotiated a Three Year Extendible Revolving Credit Facility and increased our borrowing capacity from $400 million to $900 million. This increase in borrowing capacity provided us with additional flexibility for acquisitions.

Effective August 1, 2006, we acquired Birchill for $446.8 million, including working capital adjustments. Birchill was primarily weighted towards natural gas and at the time of acquisition contributed approximately 6,300 boe/d to our production. The acquisition was financed with a combination of bank debt and the net proceeds from our issuance of 7,026,500 trust units (including the over-allotment option) at a price of $32.75 per trust unit in August 2006.

On October 19, 2006, we acquired North Atlantic, its primary asset being a medium gravity sour crude hydrocracking refinery in the Province of Newfoundland and Labrador with a daily throughput capacity of 115,000 bbl/d. This refinery is strategically located on a deep water harbour which enables crude oil feedstock delivery from the Middle East, Latin America and Russia via Very Large Crude Carriers capable of delivering shipments in excess of 2 million barrels. Its location is also relatively close to the premium markets for high quality gasoline and ultra low sulphur diesel products in the northeastern United States giving it an economic advantage over certain other refiners. Our acquisition of North Atlantic created a second business segment, refining and marketing operations. The refinery’s average throughput volumes were 86,890 bbl/d from the date of acquisition on October 19, 2006 to December 31, 2006 as the refinery was in the midst of a turnaround on the date of acquisition.

Concurrent with the closing of the North Atlantic acquisition we further expanded our Three Year Extendible Revolving Credit Facility from $900 million to $1.4 billion and established a $350 million Senior Secured Bridge Facility and a $450 million Senior Unsecured Bridge Facility. We initially financed the acquisition using our $350 million Secured Bridge Facility and our $450 million Unsecured Bridge Facility while the remainder was financed from our Three Year Extendible Revolving Credit Facility. On November 22, 2006, we issued 9,499,000 trust units at a price of $27.25 per trust unit and $379.5 million principal amount of 7.25% convertible unsecured subordinated debentures for net proceeds of $610.2 million, which included the full exercise of the underwriters’ over-allotment option. Net proceeds from the offering were used to fully repay our $450 million Senior Unsecured Bridge Facility, pay $60.3 million of the Senior Secured Bridge facility and a $99.9 million repayment of our Three Year Extendible Revolving Credit Facility.

Our Cash Flows for the three months ended December 31, 2006 were $156.3 million compared to $96.4 million in the prior year. The increase reflects the incremental cash flow generated from the Viking and Birchill properties as well as two and a half months of operations from North Atlantic. As the refinery was acquired during the fourth quarter and was only at full capacity for the month of December, our fourth quarter Cash Flows do not fully reflect the benefits we expect to realize to our future cash flows from our North Atlantic acquisition.

For the year ended December 31, 2006, we invested $376.9 million in our oil and natural gas properties, an increase of 213% over 2005. Of the total capital spent, 57% was allocated to drilling and equipping activities resulting in a total of 252 gross wells (191.4 net) drilled with a success rate of 98%. Our finding and development ("F&D") costs for the year ended December 31, 2006 were $24.30 per boe ($10.73 per boe in 2005) on a proved plus probable ("P+P") basis excluding future development costs and $26.04 per boe ($13.10 per BOE for 2005) including future development costs, reflecting a recycle ratio (operating netback divided by F&D cost) of 1.1x (3.1 for 2005). Our increased F&D costs are a result of the conversion of a larger percentage of previously booked undeveloped reserves in 2006 than in the prior year and also reflect general upward cost pressures in the industry, particularly related to the significant increase in demand for drilling rigs and the related costs to secure them which were incurred in 2006. In addition, 27% of our capital expenditures were directed towards projects that would not result in reserve additions but are included in our F&D costs for 2006: this includes $20 million of 2007 capital that was accelerated into 2006 for Hay River and Red Earth as we took advantage of favourable weather conditions in those areas. Our reserve life index (RLI) remained flat over the prior year changing from 9.4 for 2005 to 9.3 in 2006.

Subsequent to December 31, 2006, we issued $230 million principal amount of convertible debentures and 6,146,750 trust units at a price of $23.40 per trust unit for net proceeds of $357.4 million. The net proceeds from this financing were used to repay the remianing $289.7 million on the Senior Secured Bridge Facility with the remaining $67.7 million applied to the drawn portion of our Three Year Extendible Revolving Credit Facility.

On the evening of October 31, 2006, changes to the Canadian income tax treatment of distributions from publicly traded trusts were announced by the Government of Canada which have resulted in considerable decline in the valuations of all income and royalty trusts. On December 21, 2006, the Federal Minister of Finance released draft legislation to implement the proposals announced on October 31, 2006. We continue to evaluate the long term impact of these changes as well as challenge them through our active participation in the recently created Coalition of Canadian Energy Trusts.

Business Segments

With the acquisition of North Atlantic, our business has two segments: petroleum and natural gas in western Canada and refining and marketing in the Province of Newfoundland and Labrador. Our petroleum and natural gas business consists of our production and development activities and our refining and marketing business consists of a medium gravity sour crude hydrocracking refinery with a crude oil throughput capacity of 115,000 barrels per day, 66 retail gas stations, 3 cardlock locations as well as a wholesale and home heating business.

	Year ended December 31, 2006
	Petroleum and	Refining and	Total
	natural gas	marketing
Revenue	1,120,575	460,359	1,580,934
Operating income⁽¹⁾	200,978	19,740	220,718
Capital expenditures	376,881	21,411	398,292
Total assets	4,017,761	1,727,797	5,745,558

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

As our refining and marketing business was only acquired on October 19, 2006, the total revenue, operating income, Cash Flow, capital expenditures and total assets for the year ended December 31, 2005 as reflected in the consolidated financial statements relates only to the petroleum and natural gas business.

PETROLEUM AND NATURAL GAS OPERATIONS

Financial and Operating Results

On February 3, 2006, we completed a plan of Arrangement with Viking Energy Royalty Trust ("Viking") which provided for the merger of Harvest and Viking and resulted in the exchange of all of the issued and outstanding trust units of Viking for 46,040,788 trust units of Harvest and the assumption by Harvest of the covenants and obligations of Viking’s outstanding 10.5% convertible unsecured subordinated debentures and 6.40% convertible unsecured subordinated debentures as well as Viking’s bank debt for all of the crude oil and natural gas interests of Viking for an aggregate consideration of $1,975.3 million including acquisition costs. At the end of 2005, Viking’s production from these properties was approximately 24,000 boe/d comprised of approximately 50% natural gas and 50% oil and natural gas liquids with its core areas of production including Markerville, Bellshill Lake, Bashaw, Channel Lake, Alexis, Tweedie/Wappau and Greater Richdale, all in Alberta, as well as Kindersley in Saskatchewan. At December 31, 2005, Viking’s proved reserves, based on forecasted prices and costs, aggregated to 132.5 million mcf of natural gas, 23.5 million barrels of crude oil, 6.0 million barrels of heavy oil and 2.8 million barrels of natural gas liquids.

On July 26, 2006, we entered into an agreement to acquire all of the outstanding shares of Birchill Energy Inc. , private petroleum and natural gas producer in western Canada, for cash consideration of $446.8 million. At the time of acquisition, the production from these properties totaled approximately 6,300 boe/d weighted approximately 65% to natural gas (26 mmcf/d) and 35% to light crude oil and natural gas liquids (2,000 boe/d) with its core areas of production concentrated in the Markerville, Ferrier and Willisden Green areas of central Alberta. At April 30, 2006, Birchill’s proved reserves, based on forecasted prices and costs, were estimated to be 22.6 million of barrels equivalent oil by independent reservoir engineers.

The addition of these two acquisitions significantly impacts the comparability of our 2006 results with the results of the prior year as well as provides the explanations for most of the significant year-over-year variation in our petroleum and natural gas segment.

(in 000’s of Canadian dollars except as noted below)		Year ended December 31
		2006	2005	Change

Revenues	$	1,120,575	667,496	68%
Royalties		(200,109)	(113,002)	77%
Realized losses on price risk management contracts⁽¹⁾		(74,193)	(79,271)	(6%)
Unrealized gains on price risk management contracts		52,179	(45,061)	216%
Net revenues excluding realized losses on electric power fixed price contracts		898,452	430,162	109%

Operating expenses		242,474	127,258	91%
Realized gains on electric power fixed price contracts		(11,574)	(6,290)	84%
Net operating expenses		230,900	120,968	91%

General and administrative expenses		28,372	30,697	(8%)
Transportation and marketing		12,142	400	-
Transaction costs		12,072	-	-
Depreciation, depletion and accretion		413,988	178,956	131%

Operating Income⁽²⁾		200,978	99,141	103%

Cash capital expenditures (excluding acquisitions)		376,881	120,508	213%
Property and Business acquisitions, net		2,467,097	239,658	929%

Daily sales volumes
Light / medium oil (bbl/d)		27,482	17,590	56%
Heavy oil (bbl/d)		13,904	13,747	1%
Natural gas liquids (bbl/d)		2,247	824	173%
Natural gas (mcf/d)		96,578	26,461	265%
Total		59,729	36,571	63%

(1) Includes amounts realized on WTI, heavy oil price differential and currency exchange contracts and excludes amounts realized on electric power fixed price contracts and amounts realized on the series of US dollar forward purchase contracts entered into with respect to the purchase of North Atlantic.

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


Commodity Price Environment

	Year ended December 31
Benchmarks	2006	2005	Change

West Texas Intermediate crude oil (US$ per barrel)	66.24	56.56	17%
Edmonton light crude oil ($ per barrel)	72.79	68.73	6%
Bow River blend crude oil ($ per barrel)	51.04	44.28	15%
AECO natural gas daily ($ per mcf)	6.53	8.71	(25%)
AECO natural gas monthly ($ per mcf)	6.98	8.48	(18%)

Canadian / U.S. dollar exchange rate	0.882	0.825	7%

Generally, the benchmark oil prices increased during the year ended December 31, 2006 compared to the prior year. The West Texas Intermediate ("WTI") crude oil price increased by 17%, however, this increase was not fully reflected in the Edmonton light crude oil price ("Edmonton Par") due to the 7% appreciation in value of the Canadian dollar. The Canadian dollar equivalent of WTI for the year ended December 31, 2006 of $75.10 would have been $80.29 (or $5.19 higher) had the Canadian dollar/US dollar exchange rate not changed. In addition to the strengthening Canadian dollar, Edmonton Par was impacted by a higher differential to WTI during the year ended December 31, 2006 compared to 2005 primarily due to the significant increase in light synthetic oils from Alberta oil sands producers as well as the decrease in local demand as western Canadian refineries convert capacity to run more medium/heavy crude oil and less light sweet crude oil. The combination of a strengthening Canadian dollar and the widening differential between WTI and Edmonton Par resulted in only a 6% increase in Edmonton Par over the prior year while WTI increased by 17% for the same period.

For the year ended December 31, 2006, prices for heavy crude oil of $51.04 were 15% higher than in 2005 with Bow River differentials narrowing to 29.9% of Edmonton Par for the year ended December 31, 2006 compared to 35.6% for 2005. As shown in the table below, heavy oil differentials during 2006 were generally narrower than those in 2005.

	2006				2005
Differential Benchmarks	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Bow River Blend differential to Edmonton Par	30.3%	25.8%	22.9%	42.0%	40.0%	28.2%	39.6%	37.5%

For the year ended December 31, 2006 compared to the prior year, AECO natural gas daily prices saw a decrease of 25%, while monthly prices for the same periods decreased by 18%.

Realized Commodity Prices

The following table provides a breakdown of our 2006 and 2005 average commodity prices by product and our overall net realized price before and after realized losses on price risk management contracts.

	Year ended December 31
	2006	2005	Change
Light to medium oil ($/bbl)	59.82	57.07	5%
Heavy oil ($/bbl)	46.14	39.43	17%
Natural gas liquids ($/bbl)	58.54	52.40	12%
Natural gas ($/mcf)	6.76	9.05	(25%)
Average realized price ($/boe)	51.40	50.01	3%
Realized price risk management losses ($/boe)⁽¹⁾	(3.40)	(5.94)	(43%)
Net realized price ($/boe)	48.00	44.07	9%

(1) Includes amounts realized on WTI, heavy oil price differential and foreign exchange contracts and excludes amounts realized on electric power fixed price contracts and amounts realized on the series of US dollar forward purchase contracts entered into with respect to the purchase of the refinery.

Our average realized price was 3% higher before losses on price risk management contracts and 9% higher after deducting the realized losses on price risk management contracts for the year ended December 31, 2006 as compared to 2005. As the benefit of the increase in the WTI price was partially offset by a stronger Canadian dollar, the 12% overall increase in our average realized oil price for the year ended December 31, 2006 as compared to 2005 was as expected. The change in our average realized oil price is slightly higher than the change in Edmonton Par due to a narrowing of the Bow River differential to Edmonton Par from 35.6% for the year ended December 31, 2005 compared to 29.9% for the year ended December 31, 2006. As 38% of our total production is priced off of the Bow River stream, it is expected that our average realized oil price increase would be greater than the change in Edmonton Par.

For the year ended December 31, 2006, the realized price of our light to medium oil increased 5% which is reasonably in line with the Edmonton Par increase of 6% for the same period.

Our realized heavy oil price differential to Edmonton Par for 2006 was 36.6% compared to 42.6% for the prior year, a 6.0% improvement. This is expected as the majority of our heavy oil production is priced off of Bow River, which reflected a 5.7% narrowing to Edmonton Par from 35.6% for the year ended December 31, 2006 to 29.9% for the year ended December 31, 2006.

For the year ended December 31, 2006, our realized natural gas price decreased by 25% compared to the same period in 2005, while the AECO daily and monthly price decreased by 25% and 18%, respectively. For the majority of the year 85% of our natural gas sales were priced off the AECO daily benchmark, 10% were priced off AECO Monthly benchmark and the remainder sold to aggregators, and our price decrease is in line with the change in the benchmark prices. By the end of 2006, we decreased the amount of natural gas sales priced off the AECO daily benchmark to approximately 61% and increased the amount sold off the AECO monthly benchmark to 32%, with the remainder sold to aggregators.

Sales Volumes

The average daily sales volumes by product were as follows:

	Year ended December 31
		2006		2005
	Volume	Weighting	Volume	Weighting	% Volume Change
Light to medium oil (bbl/d)⁽¹⁾	27,482	46%	17,590	48%	56%
Heavy oil (bbl/d)	13,904	23%	13,747	38%	1%
Total oil (bbl/d)	41,386	69%	31,337	86%	32%
Natural gas liquids (bbl/d)	2,247	4%	824	2%	173%
Total liquids (bbl/d)	43,633	73%	32,161	88%	36%
Natural gas (mcf/d)	96,578	27%	26,461	12%	265%
Total oil equivalent (boe/d)	59,729	100%	36,571	100%	63%

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

For the year ended December 31, 2006, average production was higher than in the prior year due to the acquisition of Viking in February of 2006, our acquisition of Birchill in the third quarter of 2006 and the Hay River properties during the third quarter of 2005.

Light to medium oil production is 9,892 bbl/d higher compared to the prior year. The acquisition of Viking contributed 7,197 bbl/d while Birchill contributed 481 bbl/d and Hay River contributed an additional 3,420 bbl/d. The incremental production from the Hay River property also includes production from a $21.9 million property acquisition closed on January 19, 2006 as well as new wells from our first quarter drilling program. These increases were partially offset by disruptions in Hay River in the first and fourth quarter of 2006 as a result of routine maintenance turnarounds at production facilities, disruptions attributed to our drilling program in first quarter and a halt of production and subsequent production restrictions due to a shutdown of the Rainbow pipeline in the fourth quarter. In addition, we experienced decreases in production in the third quarter at Bellshill Lake due to power disruptions.

Heavy oil production for the year ended December 31, 2006 of 13,904 bbl/d remained relatively consistent with the prior year production of 13,747 bbl/d. The incremental production added from our 2006 drilling program and from the Viking acquisition (1,581 bbl/d) was offset by downtime in the Suffield, Hayter and Killarney areas in the second quarter and downtime in Hayter in the fourth quarter. This downtime is attributable to processing limitations at a non-operated plant as well as the installation of a acid gas compressor.

Natural gas production for the year ended December 31, 2006 of 96,578 mcf/d is significantly higher compared to average production of 26,461 mcf/d in 2005, again primarily due to the acquisition of Viking in February 2006 and our Birchill acquisition in August 2006, a natural gas weighted acquisition. The increase was partially offset by lower production volumes in the Markerville area, where approximately 3,500 boe/d of production was shut-in for the month of July and the first week of August following a fire at a non-operated gas processing facility.

Following our acquisition of Viking and Birchill, our production is weighted 45% light/medium oil, 25% heavy oil and 30% natural gas compared to 34% heavy oil and a 11% natural gas weighting in the fourth quarter of 2005. With these acquisitions, we are less exposed to fluctuations in heavy oil differentials and more exposed to natural gas price volatility.

Revenues

		Year ended December 31

(000)		2006		2005	Change
Light / medium oil sales	$	600,061	$	366,432	64%
Heavy oil sales		234,144		197,863	18%
Natural gas sales		238,367		87,437	173%
Natural gas liquids sales and other		48,003		15,764	205%
Total sales revenue		1,120,575		667,496	68%
Realized risk management contract losses⁽¹⁾		(74,193)		(79,271)	(6%)

Total revenues including realized risk management contract losses		1,046,382		588,225	78%

Realized gains on electric power price risk management contract		11,574		6,290	84%
Unrealized gains/(losses) on risk management contracts		52,179		(45,061)	(216%)
Net Revenues, before royalties		1,110,135		549,454	102%
Royalties		(200,109)		(113,002)	77%
Net Revenues	$	910,026	$	436,452	109%

(1) Includes amounts realized on WTI, heavy oil price differential and currency exchange contracts, and excludes amounts realized on electricity contracts and amounts realized on the series of swaps and forwards entered into with respect to the purchase of the refinery.

Our revenue is impacted by production volumes, commodity prices, and currency exchange rates. Light to medium oil sales revenue for the year ended December 31, 2006 was $233.6 million (or 64%) higher than for the prior year as a result of a $27.6 million favourable price variance due to the 6% increase in the Edmonton Par price and a $206.0 million favourable volume variance. The favourable volume variances over the prior year are primarily due to the acquisition of Viking (7,197 bbl/day) and Birchill (481 boe/d) in 2006 and the Hay River (3,420 bbl/d) property in the third quarter of 2005, as well as the focus of our drilling program which is focused on light to medium oil production.

Heavy oil sales revenue for the year ended December 31, 2006 increased $36.3 million (or 18%) compared to the same period in the prior year due to a favourable price variance of $34.0 million and a favourable volume variance of $2.3 million. The rising crude oil price environment, including the narrowing of heavy oil differentials, resulted in higher realized prices on our heavy oil. The volume variance is primarily attributed to the Viking assets and new wells drilled in Hayter and Suffield. These volume additions were partially offset by natural declines and higher water cuts in a portion of our heavy oil production.

Natural gas sales revenue increased by $150.9 million (or 173%) for the year ended December 31, 2006 over the prior year due to an unfavourable price variance of $80.7 million and a favourable volume variance of $231.6 million. Natural gas prices during the current year have been relatively weak compared to the prior year with the AECO daily price showing a 25% year over year reduction. The favourable volume variance is entirely attributed to the annualized incremental gas production of 65,955 mcf/d from the Viking properties and 6,799 mcf/d from the Birchill properties both acquired in 2006.

For the year ended December 31, 2006 natural gas liquid sales and other increased by $32.2 million (or 205%) compared to the year ended December 31, 2005. The increase is due to a $5.0 million favourable price variance and a $27.2 million favourable volume variance which is generally due to a higher pricing environment and additional production volumes from the Viking and Birchill properties.

Price Risk Management Contracts

Details of our price risk management contracts outstanding at December 31, 2006 are included in Note 18 of our audited consolidated financial statements for the year ended December 31, 2006 filed on SEDAR @ www.sedar.com. The table below provides a summary of net gains and losses on risk management contracts:

	Year ended December 31
						2006						2005
(000s)		Oil		Gas	Currency		Electricity			Total		Total
Realized (losses) / gains on price risk management contracts	$	(80,832)	$	4,838	$	1,801⁽¹⁾	$	11,574	$	(62,619)	$	(72,981)
Unrealized (losses) / gains on price risk management contracts		53,820		(662)		(5,309)		3,932		51,781		(36,081)
Amortization of deferred charges relating to risk management contracts		-		-		-		-		-		(10,759)
Amortization of deferred gains relating to risk management contracts		-		-		-		398		398		1,779
Total (losses) / gains on risk management contracts	$	(27,012)	$	4,176	$	(3,508)	$	15,904	$	(10,440)	$	(118,042)

(1) Exludes amounts realized on the series of US dollar forward purchase contracts entered into with respect to the purchase of North Atlantic

Our total realized loss on oil and gas price and currency exchange risk management contracts was $74.2 million for the year ended December 31, 2006 compared to $79.3 million for the same period in 2005.

Our realized loss on oil price contracts for the year ended December 31, 2006 of $80.8 million was relatively unchanged from the $80.7 million realized in the prior year. In 2006, we had WTI price risk management contracts on approximately 25,000 bbl/d with downside protection at an average floor price of US $43.80 per bbl and 60% participation in prices over US $43.80 as compared to price risk management contracts that had fixed price caps in 2005. As compared to 2005, the average WTI price increased by US $9.68 to US $66.24 in 2006 but our participating price risk contracts limited our participation in prices over US$43.80 resulting in the losses on WTI oil price contracts, in U.S. dollars, being 9% higher than in the prior year. This increase in losses due to WTI pricing contracts in 2006 was offset by the strengthening of the Canadian dollar and to a lesser extent an increase in the realized gains from fixed price contracts for heavy oil price differentials.

Realized gains on our heavy oil differential contracts for the year ended December 31, 2006 totalled $6.8 million (or $0.31 per boe) compared to $3.9 million (or $0.29 per boe) in the prior year. During the first and fourth quarter of 2006 when heavy oil differentials averaged 42.0% and 30.3%, respectively, we realized gains on these contracts which were partially offset by losses during the second and third quarters of 2006 when heavy oil differentials averaged 22.9% and 25.8%, respectively. Our heavy oil differential contracts result in a contractual average differential from WTI of 28-29% for 2006 and 2005. For the year ended December 31, 2005, we only had heavy oil differential contracts in place from July 1, 2005 onwards.

In early 2006, we acquired Viking which significantly changed our production mix from 11% natural gas in the prior year to approximately 30% for the year ended December 31, 2006. In anticipation of soft natural gas prices in the summer of 2006, we entered into one natural gas price risk management contract for the period from April 2006 through March 2007 for 25,000 GJ/d with a floor price of $7.00 and a price cap of approximately $12.50 and another contract for the same period for 25,000 GJ/d with a floor price of $5.00 and a price cap of $13.55. We also entered into a contract for 5,000 GJ/d for the period from April 2006 through October 2006 with a floor price of $9.00 and a price cap of $13.06. The contracts with floor prices of $7.00 and $9.00 resulted in favourable settlements aggregating to a gain of $4.8 million in 2006. There were no natural gas price risk management contracts in place for 2005.

In 2006, we settled currency exchange rate contracts and accumulated a net gain of $1.8 million compared to $1.4 million in the prior year. The gain in 2006 is primarily the result of our participation in an oil sales contract which entitles us to elect on a monthly basis to accept settlement of the prior month’s sales proceeds in US currency or to fix the currency exchange rate for a Canadian dollar settlement. In 2006, we also settled fixed rate currency exchange contracts on US $12.9 million at an average rate of $0.86 resulting in a nominal gain. For 2007, we have entered into contracts to fix the currency exchange rate on US $ 105.0 million at an average rate of approximately $0.89.

We have also entered into risk management contracts that provide protection from rising electric power prices. We realized gains on these contracts of $11.6 million (or $0.53 per boe) for the year ended December 31, 2006 and $6.3 million (or $0.47 per boe) for the prior year. Additional details on these contracts is provided under the heading "Operating Expense" of this MD&A.

The unrealized gains on our risk management contracts for the year ended December 31, 2006, excluding amortization of deferred gains, was $51.8 million compared to a loss of $36.1 million loss for the prior year. Collectively, our risk management contracts had an unrealized mark-to-market deficiency of $1.9 million as at December 31, 2006 compared to a mark-to-market deficiency of $52.6 million at December 31, 2005. Refer to Note 18 to the consolidated financial statements for the year ended December 31, 2006 filed on SEDAR at www.sedar.com for further details of the price risk management contracts outstanding at December 31, 2006.

Also included in our unrealized gains on risk management contracts is the amortization of the deferred charges and credits that were deferred when we ceased to apply hedge accounting principles. This represented a recovery of $398,000 for the year ended December 31, 2006 and $1.8 million for the year ended December 31, 2005. These amounts are discussed further under the heading "Deferred Charges and Credits".

Subsequent to December 31, 2006, we have entered into the following natural gas price risk management contracts:


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

Royalties

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

For the year ended December 31, 2006, our net royalties as a percentage of gross revenue were 17.8% (16.9% - year ended December 31, 2005) and aggregated to $200.1 million ($113.0 million – year ended December 31, 2005). The increase in the royalty rate is due to the higher rates associated with the Viking assets acquired in February 2006 (royalty rates of approximately 18%) and the Hay River properties acquired in August 2005 (royalty rates of approximately 24-25%). In addition, effective April 1, 2005 a 3.6% surcharge was applied by the Saskatchewan government on gross resource revenues earned in Saskatchewan (2% for production from wells drilled subsequent to October 2002) which affects the first quarter of 2006 but not the first quarter in the prior year.

Operating Expense

	Year ended December 31
									Per BOE
($000s)		2006	Per BOE			2005		Per BOE	Change
Operating expense
Power	$	61,056	$	2.80	$	39,452	$	2.96	(5%)
Workovers		51,151		2.34		29,099		2.18	7%
Repairs and maintenance		38,969		1.79		17,316		1.30	38%
Labour – internal		20,719		0.95		7,631		0.57	67%
Processing fees		15,311		0.70		4,268		0.32	119%
Fuel		7,442		0.34		6,451		0.48	(29%)
Labour – external		13,012		0.60		5,917		0.44	36%
Land leases and property tax		19,319		0.89		11,998		0.90	(1%)
Other		15,495		0.71		4,726		0.35	103%
Total operating expense		242,474		11.12		126,858		9.50	17%
Realized gains on electric power price
risk management contracts		(11,574)		(0.53)		(6,290)		(0.47)	13%
Net operating expense	$	230,900	$	10.59	$	120,568	$	9.03	17%

Transportation and marketing expense	$	12,142	$	0.56	$	400	$	0.03	1767%

Total operating expense increased by $115.6 million to $242.5 million for the year ended December 31, 2006 compared to the prior year. For the year ended December 31, 2006, approximately $90.6 million of the increase is due to increased activity associated with the Viking properties acquired in February 2006 and the remainder of the increase is attributed to Birchill acquisition in August 2006 and Hay River in August 2005 along with continued high demand for oilfield services leading to higher costs for well servicing, workovers, labour and well maintenance.

On a per barrel basis our operating costs have increased to $10.59 per boe, 17% over the prior year. In addition to the general upward cost pressures in the industry, the increase is partially attributed to higher processing fees as we have a greater proportion of non-operated properties in our portfolio as a result of the acquisition of Viking. We incur higher processing fees on non-operated properties as in most cases, although we own an interest in the well, we do not own an interest in the processing plant and we are charged a fee associated with processing.

Our operating expenses will benefit from our 2006 capital spending program, a portion of which was directed towards operating cost reduction initiatives such as the water disposal and fluid handling project in Suffield where we incurred approximately $13 million in capital expenditures to lower power costs to operate high water cut wells. These projects, combined with the acquisition of Birchill in August 2006 which has lower average operating costs per boe, will assist in offsetting the upwards cost pressures in the oil and gas services industry.

Our transportation costs of $12.1 million ($400,000 – year ended December 31, 2005) are primarily related to delivering natural gas to Alberta’s natural gas sales hub, the AECO Storage Hub, and to a lesser extent, our costs of trucking crude oil to pipeline receipt points. The increase in our 2006 transportation costs over the prior year is substantially related to the incremental natural gas production with our acquisition of Viking and Birchill which added over 70,000 mcf/d of natural gas production. In addition we also changed our relationship with the pipeline operators such that the transportation commitments are now a direct responsibility of Harvest rather than the independent marketer of our production. As to the $2.2 million of marketing costs included in our 2006 transportation and marketing expense, we have built an "in-house" marketing capability during the fourth quarter of 2006 and have concurrently terminated our agreement with the independent marketer.

Electricity costs represent approximately 25% of our total operating costs (approximately 31% for the year ended December 31, 2005). For the year ended December 31, 2006, electricity costs per megawatt hour ("MWh") were 14% higher than they were in the prior year. These increases were offset by the Viking properties which have lower electric power usage per boe of production and the Hay River properties, which operate using internally generated electric power. The combination of these two factors, as well as the impact of our fixed price electricity contracts, has resulted in a lower per boe electric power cost despite rising prices. The following table details the electric power costs per boe before and after the impact of our hedging program.

	Year ended December 31
($ per boe)		2006		2005	Change
Electric power costs	$	2.80	$	2.96	(5%)
Realized gains on electricity risk management contracts		(0.53)		(0.47)	13%
Net electric power costs	$	2.27	$	2.49	(9%)
Alberta Power Pool electricity price ($ per MWH)	$	80.48	$	70.35	14%

Approximately 65% of our estimated Alberta electricity usage was protected by fixed price purchase contracts at an average price of $51.48 per MWh through December 2006. Of our estimated 2007 and 2008 Alberta electricity usage, 52% is protected at an average price of $56.69 per MWh These contracts will help moderate the impact of future cost swings, as will capital projects undertaken during 2006 and future periods that are dedicated to increasing our power efficiency.

Operating Netback

	Year ended December 31
($ per boe)		2006		2005
Revenues	$	51.40	$	50.01
Realized loss on risk management contracts⁽¹⁾		(3.40)		(5.94)
Royalties		(9.18)		(8.47)
Operating expense⁽²⁾		(10.59)		(9.03)
Transportation and marketing expense		(0.56)		(0.03)
Operating netback⁽³⁾	$	27.67	$	26.54

(1) Includes amounts realized on WTI, heavy price differential and foreign exchange contracts, and excludes amounts realized on electricity contracts and amounts realized on the series of swaps and forwards entered into with respect to the purchase of the refinery.

(2) Includes realized gain on electricity risk management contracts of $0.53 per boe and $0.47 per boe for the year ended December 31, 2006 and 2005

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

Operating netback represents the total net realized price we receive for our production after direct costs. Our operating netback is $1.13 per boe higher for the year ended December 31, 2006 than for the prior year. Higher oil prices more than offset lower natural gas prices in 2006 compared to 2005 resulting in a higher realized price per boe by $1.39/boe, which was positively impacted by a further $2.54/boe due to lower losses realized, on a per boe basis, on our price risk management program. Gains in revenues were offset by higher royalties by $0.71/boe, higher operating costs of $1.56/boe, and higher transportation costs of $0.53/boe.


General and Administrative ("G&A") Expense

		Year ended December 31
($000s except per boe)		2006		2005	Change
Cash G&A⁽¹⁾	$	27,485	$	13,571	103%
Unit based compensation expense		887		17,126	(95%)
Total G&A	$	28,372	$	30,697	(8%)

Cash G&A per boe ($/boe)		1.26		1.02	24%

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

(1) Cash G&A excludes the impact of our unit based compensation expense and other one time transaction costs.

For the year ended December 31, 2006, Cash G&A costs increased by $13.9 million (or 103%) compared to the same period in 2005 which is attributed mainly to increased staffing levels with our integration of the staff from our acquisition of Viking. Approximately $21.4 million (or 78%) of our year end Cash G&A expenses are related to salaries and other employee related costs while in the prior year only $8.5 million (or 62%) of our Cash G&A was made up of these costs. In addition to the rising costs for technically qualified staff, the acquisition of Viking in February 2006 doubled our overall staffing levels, adding approximately 100 additional employees. The remainder of the increases for the year ended December 31, 2006 compared to 2005, are due to the work undertaken for compliance with the Sarbanes Oxley Act, higher office rental costs required for the additional staff, increased travel costs related to the refinery acquisition and $600,000 of costs incurred for third party consultants used to evaluate acquisition opportunities that have subsequently been abandoned.

Our unit based compensation plans provide the employee with the option of settling outstanding awards with cash. As a result, our unit based compensation expense is determined using the intrinsic method being the difference between the trust unit trading price and the strike price of the unit appreciation rights ("UAR") adjusted for the proportion that is vested. Our total unit based compensation expense for the year ended December 31, 2006, was $9.9 million, of which $9.0 million was allocated to transaction costs and $0.9 was allocated to G&A expense. A reversal of expenses is recognized in periods where our trust unit price decreases from the beginning of the period to the end of the period. Our opening trust unit market price was $37.19 at January 1, 2006 and at December 31, 2006 our trust unit price had decreased to $26.23. As a result, we have recorded a recovery of $8.1 million on unexercised UARs for the year ended December 31, 2006. Our total unit based compensation expense, including that portion which has been allocated to transaction costs, decreased by $7.3 million for the year ended December 31, 2006 compared to the prior year.

We have recorded transaction costs of $12.1 million which represent one time costs incurred as part of the acquisition of Viking. All of Harvest’s outstanding UARs vested on February 3, 2006 in conjunction with the plan of arrangement and we have reflected $9.0 million as a result of the accelerated vesting of our units as a transaction cost. In addition, the remaining $3.1 million recorded as transaction costs are related to severance payments made to Harvest employees upon merging with Viking.

Depletion, Depreciation and Accretion Expense

		Year ended December 31
(000s except per boe)		2006		2005	Change
Depletion and depreciation	$	381,085	$	155,841	145%
Depletion of capitalized asset retirement costs		16,950		14,345	18%
Accretion on asset retirement obligation		15,953		8,770	82%
Total depletion, depreciation and accretion	$	413,988	$	178,956	131%
Per boe ($/boe)		18.99		13.41	42%

Our overall depletion, depreciation and accretion ("DD&A") expense for the year ended December 31, 2006 is $235.0 million higher compared to 2005. Of this, $113.3 million is due to the incremental production from the Hay River acquisition made in the latter half of 2005 and the merger with Viking in early 2006 and the remaining $121.7 million of the increase is attributed to a higher depletion rate per boe as acquisitions have increased our overall corporate DD&A rate due to their higher cost as compared to prior property acquisitions.

Capital Expenditures

	Year ended December 31
(000s)		2006		2005
Land and undeveloped lease rentals	$	9,756	$	1,838
Geological and geophysical		6,709		285
Drilling and completion		214,964		80,170
Well equipment, pipelines and facilities		124,518		32,644
Capitalized G&A expenses		13,141		3,830
Furniture, leaseholds and office equipment		7,793		1,741
Development capital expenditures excluding acquisitions	$	376,881	$	120,508
Non-cash capital additions (recoveries)		(533)		3,275
Total development capital expenditures excluding acquisitions and non-cash items		376,348		123,783

In the 2006 we invested $376.9 million into our portfolio of drilling, optimization and enhancement activities compared to $120.5 million in 2005. Approximately 57% of annual expenditures were spent on drilling 252 gross wells with a success rate of 98%, compared to 94 gross wells drilled in 2005 with a success rate of 95%. We continued to focus our drilling activity on oil opportunities as we expect the current strong oil pricing environment to continue. The WTI benchmark price for crude oil averaged US$66.24 in 2006 compared to US$56.56 in 2005.

The following summarizes Harvest’s participation in gross and net wells drilled during 2006:

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

South East Saskatchewan	37.0	36.8	37.0	36.8	-	-
Hay River	27.0	27.0	27.0	27.0	-	-
Markerville	26.0	11.5	26.0	12.1	-	-
Wainwright	14.0	14.0	14.0	14.0	-	-
Hayter	16.0	15.2	16.0	15.2	-	-
Suffield	16.0	16.0	16.0	16.0	-	-
Red Earth	19.0	16.8	19.0	16.8	-	-
Lloyd	12.0	12.0	12.0	12.0	-	-
Parkland	8.0	1.9	8.0	1.9	-	-
Red Deer	7.0	2.1	7.0	2.1	-	-
Other Areas	70.0	38.1	65.0	33.9	5.0	3.6
Total	252.0	191.4	247.0	187.8	5.0	3.6

(1) Excludes 23 additional wells that we have an overriding royalty interest in.

Our most active drilling area was southeast Saskatchewan where we drilled 37 gross horizontal and vertical wells during the year, accessing both infill potential on our existing pools, and previously untapped hydrocarbon deposits. A vertical stratigraphic test in the Kenosee area discovered a significant new oil pool, which we expect to begin exploiting with horizontal wells in early 2007. The majority of the 27 gross wells that were drilled at Hay River in 2006 were drilled in the first quarter to continue our development of this large Bluesky oil pool which we acquired in August 2005. Production at Hay River peaked at just over 7,300 boe/d in May of 2006 following the successful completion of our winter program. At Markerville, 26 gross wells were drilled in the year with 4 horizontal wells targeting liquids rich sweet natural gas in the Pekisko formation, and the remainder of the wells accessing natural gas in the shallow Edmonton sands formation. After confirming new hydrocarbon accumulations in the Slave Point formation, a total of 19 gross wells were drilled at Red Earth in 2006, including a new pool discovery. At Hayter, we continue to drill infill horizontal wells with a total of 16 gross wells drilled seeking to further increase the recovery factor from this large Dina heavy oil pool. Similarly at Suffield, we continue to find incremental oil from the Glauconitic formations with a total of 16 gross infill horizontal wells drilled.

The $124.5 million of well equipment, pipelines and facilities expenditures includes approximately $13 million for water handling upgrades at Suffield to increase total fluid handling capacity from this field, to improve the overall efficiency of our water separation and extraction processes, and to accommodate the recent and future year drilling programs. At Hay River we started the construction of an all season access road with an expenditure of $6.6 million. This will enable us to access our Hay River operations year round for well servicing and optimization activity. Prior to the initial construction of the access road, Hay River was a winter access only property. We also completed a tie-in of compression at our Ferrier project during the year for an expenditure of $5 million, and we were able to bring on approximately 400 boe/d at the end of August.

As a result of our 2006 drilling program we added 18.9 mmboe of proved plus probable reserves (prior to the conversion of previously booked undeveloped reserves) replacing approximately 87% of 2006 production and resulting in finding and development costs ("F&D") before changes in future development capital ("FDC") of $24.30 per boe on a proved plus probable basis and $26.04 per boe after FDC. This represents an increase of $13.57 per boe and $12.94 over the prior year F&D costs of $10.73 including FDC and $13.10 including FDC, respectively. Finding Development and Acquisition ("FD&A") costs per boe on a proved plus probable basis for the year ended December 31, 2006 were $23.13 before FDC and $24.59 after FDC, compared to FD&A costs for 2005 before FDC of $11.78 and $15.56 including FDC costs. Our increased F&D costs are a result of the conversion of a larger percentage of previously booked undeveloped reserves in 2006 than in the prior year and also reflect general upward cost pressures in the industry, particularly related to the significant increase in demand for drilling rigs and the related costs to secure them which were incurred in 2006. In addition, 27% of our capital expenditures were directed towards projects that would not result in reserve additions but are included in our F&D costs for 2006, this includes $20 million of 2007 capital that was accelerated into 2006 for Hay River and Red Earth as we took advantage of favourable weather conditions in those areas.

Property Acquisitions and Divestitures

Cash property acquisitions (net of dispositions) year-to-date are $44.9 million including $38.0 million on heavy oil properties acquired in Saskatchewan in the fourth quarter, $18.4 million for an acquisition in the Hay River area, $3.5 million in the South Killarney area and $3.1 million in the Crossfield East area. These acquisitions were offset by the disposition of $13.3 million and $6.7 million in the Crossfield and Rainbow areas, respectively, as well as other small acquisitions and dispositions. The dispositions allowed us to take advantage of an attractive market condition as we were able to sell these minor interests at a producing metric of approximately $100,000 per boe/d. We also acquired a total of 70,200 net acres of undeveloped land during 2006 at an average price of $131/acre. Two major land parces were acquired, including 27 sections (17,280 acres) of oilsands rights in Red Earth for total consideration of $2 million, and almost 13,000 acres of petroleum and natural gas rights at Red Earth for a total consideration of $1.5 million.

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 have recorded $656.2 million of goodwill related to our petroleum and natural gas segment compared with $43.8 million at December 31, 2005. In conjunction with our acquisition of Viking we recorded $612.4 million of goodwill. 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.

Asset Retirement Obligation ("ARO")

In connection with a property acquisition or development expenditure, we record the fair value of the ARO as a liability in the same year as the expenditure occurs. Our ARO costs are capitalized as part of the carrying amount of the assets, and are depleted and depreciated over our estimated net proved reserves. Once the initial ARO is measured, it must be 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 $91.8 million in the year ended December 31, 2006. As a result of the merger with Viking, we added $60.5 million to our ARO, and the remainder of the increase in the year to date is due to additions resulting from the acquisition of Birchill, drilling activity in the year, an increased estimate of existing liabilities, and accretion expense, offset by actual asset retirement expenditures made in the period.

REFINING AND MARKETING OPERATIONS

Financial and Operating Results

On October 19, 2006 Harvest completed its acquisition of all of the shares of North Atlantic Refining Limited ("North Atlantic") and related businesses and North Atlantic concurrently entered into a supply and off take agreement with Vitol Refining, S.A. (the "Supply and Offtake Agreement") (collectively, the "Acquisition").

The principal asset of North Atlantic is a medium gravity sour crude hydrocracking refinery with a 115,000 b/d capacity located in the Province of Newfoundland and Labrador (the "Refinery"), and a marketing division with 69 gas stations, a home heating business and a commercial and wholesale petroleum products business, all located in the Province of Newfoundland and Labrador. The Refinery is capable of processing a wide range of crude oils and feedstocks with a sulphur content as high as 3.5% and API gravity in the range of 25° to 40°, has approximately seven million barrels of tankage including six 575,000 barrel crude tanks and has a dock facility capable of handling vessels in excess of 330,000 dwt that carry up to 2 million barrels of crude oil which typically results in significantly lower per barrel transportation charges. The Refinery’s feedstocks are primarily from the Middle East, Russia and Latin America. The Refinery’s product slate is weighted towards high quality diesel fuel, jet fuel, and gasoline that are currently compliant with product specifications (including sulphur, cetane and aromatic content) that are becoming increasingly restrictive and constraining supply. Approximately 10% of North Atlantic’s refined products are sold in the Province of Newfoundland and Labrador while approximately 90% are sold in the U.S. east coast markets, primarily Boston and New York City. Through its marketing division, North Atlantic operates a petroleum marketing and distribution business in the Province of Newfoundland and Labrador with average daily sales over 11,000 barrels. The North Atlantic brand has been positioned in the Newfoundland marketplace as a local company with its retail gasoline business operating 66 retail gas stations and 3 cardlock locations capturing a market share of approximately 15% to 20%.

Concurrent with our acquisition of North Atlantic, North Atlantic entered into the Supply and Offtake Agreement with Vitol Refining S.A. The Supply and Offtake Agreement provides that the ownership of substantially all crude oil feedstock and refined product inventory at the Refinery be retained by Vitol Refining S.A. and that during the term of the Supply and Offtake Agreement, Vitol Refining S.A. will be granted the right and obligation to provide crude oil feedstock for delivery to the Refinery as well as the right and obligation to purchase all refined products produced by the refinery. The Supply and Offtake Agreement also provides that Vitol Refining S.A. will also receive a time value of money amount reflecting the cost of financing the crude oil feedstock and sale of refined products. Further, the Supply and Offtake Agreement provides North Atlantic with the opportunity to share the incremental profits and losses resulting from the sale of products beyond the U.S. East Coast markets.

Effective with the closing of this acquisition on October 19, 2006, the operating results of North Atlantic are included in the operations of Harvest with segmented reporting for each of the petroleum and natural gas operations in western Canada and the refining and marketing business in the Province of Newfoundland and Labrador. The operating results of North Atlantic 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. While December’s operations are more reflective of normal operations, North Atlantic did experience an unplanned disruption with its naptha hydrotreater due to a pipe rupture and additional downtime due to a disruption in electric power service from Newfoundland and Labrador Hydro which impacted December’s throughput by approximately 3,000 bbl/day The following table summarizes the North Atlantic financial and operational information for the period from October 19, 2006 to December 31, 2006:

(in 000’s of Canadian dollars unless otherwise noted)

Revenues	460,359

Purchased products for resale and processing	386,014

Gross Margin⁽¹⁾	74,345

Costs and expenses
Operating expense	18,378
Purchased energy expense	15,685
Marketing expense	5,060
Depreciation and amortization expense	15,482

Operating income⁽¹⁾	19,740

Cash capital expenditures	21,411

Feedstock volume (bbl/day)⁽²⁾	86,890

Yield (000’s barrels)
Gasoline and related products	1,875
Ultra low sulphur diesel	2,624
Heavy fuel oil	1,752
Total	6,251

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

⁽²⁾ Barrels per stream day are calculated using total barrels of crude oil feedstock and Vacuum Gas Oil (VGO) divided by 73 days

Refining Benchmark Prices

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

Similar to the petroleum and natural gas industry, the refining industry has a few benchmark prices from which to assess a particular refinery’s performance. Typically, these benchmarks include prices for refined products such as Reformulated Blendstock for Oxygenate Blending gasoline ("RBOB gasoline") and heating oil. As a benchmark indicator of refining margins, The New York Mercantile Exchange ("NYMEX") "2-1-1 Crack Spread" is a refining benchmark calculated by assuming that the processing of two barrels of light sweet crude oil (defined as a WTI quality) produces one barrel of gasoline and one barrel of diesel into the New York market where product prices are set in relation to the NYMEX gasoline and NYMEX heating oil prices. The following table provides the average prices for the period from October 19, 2006 to December 31, 2006 for a few refining industry benchmark prices:


West Texas Intermediate crude oil (US$ per barrel)	60.44
RBOB gasoline (US$/barrel)	66.78
Heating Oil (US$/barrel)	71.82
2-1-1 Crack (US$/barrel)	8.86

Canadian / U.S. dollar exchange rate	0.883

Although the "2-1-1 Crack Spread" is a reasonable benchmark, the North Atlantic refinery differs in that it produces a significant amount of heavy fuel oil relative to the "2-1-1 Crack Spread" benchmark and also processes primarily a medium gravity sour crude oil rather than a WTI quality of light sweet crude oil. In addition North Atlantic purchases approximately 8,000 to 10,000 bbl/d of additional VGO to optimize the throughput of its Isomax unit which is a key unit in the production of gasoline and diesel fuel and this further differentiates the North Atlantic refinery gross margin from the "2-1-1 Crack Spread" benchmark.

North Atlantic’s Refinery Feedstock

During the period from October 19, 2006 to December 31, 2006, North Atlantic’s crude oil feedstocks were as follows:

(in 000’s of Canadian dollars unless notes)	Cost of Goods Sold	Volume (in 000s	US$ per bbl
		bbls)
Basrah	305,396	5,372	50.21
Hamaca	28,826	524	48.59

Total Crude Feedstock	334,222	5,896	50.07

Vacuum Gas Oil purchased	26,645	446	52.77

Total Feedstock/Throughput	360,867	6,342	50.26

Other additives	6,834

Total of Feedstock and Other Additives	367,701

During the period from October 19, 2006 to December 31, 2006, the Refinery feedstock was comprised of 80,767 bbl/d of crude oil, approximately 91% Basrah (a medium sour crude) from Iraq in the Middle East and 9% Hamaca crude from Venezula in South America, and 6,100 bbl/d of VGO with prices per barrel, including all costs of transporting to the North Atlantic site, of approximately US$50.07 and US$52.77, respectively. Relative to the average price of the WTI benchmark, the medium gravity sour crude purchased by North Atlantic represents a US$10.37 per barrel price differential on feedstock.

North Atlantic’s Refined Products

Product yields are impacted by the crude oil feedstock as well as refinery performance and with its feedstock being primarily Basrah for the period from October 19, 2006 to December 31, 2006, North Atlantic anticipated a refined product yield of approximately 31% gasoline, 41% ultra low sulphur diesel and jet fuel and 27% heavy fuel oil. North Atlantic’s actual yields for this period were as follows:

(in 000’s of Canadian dollars unless notes)	Refinery Revenues	Volume (in 000’s	US$ per bbl/US$ per gal
		bbls)
Gasoline and related products	131,643	1,875	62.01/1.48
Ultra low sulphur diesel and jet fuel	216,435	2,624	72.85/1.73
Heavy fuel oil	78,969	1,752	39.81/0.95
	427,047	6,251
Other	7,617
Total refined products	434,664

Total Yield (as a % of feedstock)		99%

For the period from October 19, 2006 to December 31, 2006, North Atlantic’s actual yields were expected with 1% more heavy fuel oil and 1% less gasoline. Relative to the benchmark prices, North Atlantic received US$62.01 per bbl (US$1.48 per gallon) for its gasoline as compared to US$1.59 per gallon for NYMEX RBOB gasoline and US$72.85 (US$1.73 per gallon) for its ultra low sulphur diesel and jet fuel products compared to US$1.71 for NYMEX heating oil. The gasoline price is slightly less than the NYMEX reference price due to shipping costs to New York harbour. The US$0.02 per gallon premium over the NYMEX heating oil price reflects the higher product quality of North Atlantic’s diesel fuel and jet fuel less shipping costs to New York harbour.

The value of the heavy fuel oil produced by North Atlantic will fluctuate over the longer term as "bottoms upgrading" projects come online reducing the supply of heavy fuel oil while shipping companies and electric utilities continue to burn high and low sulphur heavy fuel oil. Relative to the average price North Atlantic paid for its Basrah feedstock, the selling price for its heavy fuel oil results in a negative contribution to North Atlantic of US$10.40 per barrel. The amount of heavy fuel oil produced by North Atlantic presents an opportunity to change its refinery configuration to produce more gasoline and diesel by upgrading its heavy fuel oil.

North Atlantic’s Gross Margin

North Atlantic’s gross margin is comprised of the crack spread from its refinery operations as well as the margin on its marketing and other related businesses. For the period from October 19, 2006 to December 31, 2006, contribution from the refinery operations and marketing were as follows:

(in 000’s of Canadian dollars unless notes)	Refinery	Marketing	North Atlantic ⁽¹⁾
	Operations	Operations

Sales revenue	434,665	68,099	460,359
Cost of products for processing and resale	367,701	60,718	386,014
Gross margin⁽²⁾	66,964	7,381	74,345

(1) The North Atlantic sales revenue and cost of products for processing and resale are net of inter-segment sales of $42,405 reflecting the refined products produced by the Refinery Operations and sold by the Marketing Operations

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

North Atlantic’s crack spread is comprised of the following: $83.7 million of gross margin on the production of gasoline and ultra low sulphur diesel and jet fuel from its crude oil feedstock (including a heavy sour differential of approximately $47.4million) and 9.7 million on the production of gasoline and ultra low sulphur diesel and jet fuel from purchased VGO offset by a $26.4 million negative contribution from the production of heavy fuel oil and other refined products. Overall, relative to the industry "2-1-1 Crack Spread" benchmark of US$8.86 during the period, North Atlantic’s crack spread averaged US$9.32 per barrel of throughput. The $7.4 million of gross margin from the Marketing Operations is composed of the margin from the both retail and wholesale distribution of gasoline, home heating fuels and related appliances as well as the revenues from marine services including tugboat revenues.

Operating Expenses

For the period from October 19, 2006 to December 31, 2006, North Atlantic’s operating costs were as follows:

(in 000’s of Canadian dollars unless notes)		$/bbl
Operating expense	18,378	2.90
Purchased energy expense	15,685	2.47
Total	34,063	5.37

Marketing expense	5,060	0.80

The largest component of operating expense is wages and benefits which totaled $11.2 million (approximately 61% of operating expense) while the other significant components were maintenance and repairs costs ($2.1 million), insurance ($1.4 million) and chemicals ($0.9 million). The wages and benefits and maintenance costs are higher than normal due to the electrical power outage in December while the unplanned shutdown on the naptha hydrotreater unit during November and December resulted in a greater than normal amount of chemicals used in the operations. Other operating expenses are in line with expectations. Overall operating expenses were $2.90 per barrel during the period as compared to our expectations during a normal operations period of approximately $2.20 to $2.40 per barrel.

Purchased energy is required to provide heat and to operate the refinery which consists of purchased low sulphur fuel oil and electric power, respectively. During the period from October 19, 2006 to December 31, 2006, our energy usage was higher than expected due to the power failure and the energy consumption during the subsequent unit start-up following both the planned and unplanned maintenance. Our energy costs were $2.47 per barrel for the period, however, during a normal operating period, we would expect our purchased energy cost to be on average less than $2.20.

Marketing expense is comprised of $0.5 million of marketing fees (US $0.08 per barrel of feedstock) to acquire feedstock and $4.6 million of "Time Value of Money" incurred pursuant to the supply and offtake agreement entered into with Vitol Refining S.A.

Capital Expenditures

During the period from October 19, 2006 to December 31, 2006, capital spending totaled $21.4 million with $5.8 million incurred for the replacement of Heater 1501 convection section, $4.6 million for ongoing tank recertification and $4.4 million to complete the naphtha hydrotreater/platformer turnaround. There was also $1.7 million spent to complete the construction of a new truck loading facility.

Depreciation Expense

(000s of Canadian dollars)	2006
Tangible assets	14,243
Intangible assets	1,239
Total	15,482

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

Goodwill

On October 19, 2006, we recorded $203.9 million of goodwill in connection with the acquisition of the refinery as the purchase price of the acquired business exceeded the fair value of the net identifiable assets and liabilities of that acquired business. As the refining assets are held in a self-sustaining subsidiary with a U.S. dollar functional currency, the value of the goodwill will be adjusted at each period end to reflect the changing U.S. dollar currency exchange rate. Goodwill will be assessed annually for impairment or more frequently if events or changes in circumstances occur that would reasonably be expected to reduce the fair value of the acquired business to a level below its carrying amount.


FINANCING AND OTHER
		��
Interest Expense

		Year ended December 31

($000s except per boe)		2006		2005	Change
Interest on short term debt	$	1,489	$	4,089	(64%)
Amortization on deferred charges – short term debt		3,375		2,498	35%
Total interest on short term debt		4,864		6,587	(26%)

Interest on long-term debt
Senior notes		22,624		23,952	(6%)
Convertible debentures		20,229		2,865	606%
Bank loan		30,967		651	4657%
Amortization of deferred charges – long term debt		5,073		2,356	115%
Total interest on long term debt		78,893		29,824	165%
Total interest expense	$	83,757	$	36,411	130%

Interest expense, which includes the charges on outstanding bank debt, convertible debentures and senior notes as well as the amortization of related financing costs, was $47.3 million higher for the year ended December 31, 2006 than the prior year. Of this increase, $27.7 million is due to increases in short term and long term bank loan interest from the significant increase in the amounts drawn on our credit facilities resulting from the assumption of approximately $106.2 million of bank debt in the acquisition of Viking and incremental borrowings to finance the acquisition of Birchill and North Atlantic.

On February 3, 2006 we entered into a new credit agreement that established a Three Year Extendible Revolving Credit Facility that increased our borrowing capacity to $900 million with interest calculated using a floating rate based on banker’s acceptances plus 65 to 115 basis points based on our Senior Debt to Cash Flow ratio as defined in the credit agreement. On October 19, 2006, and concurrent with our acquisition of North Atlantic, this facility was amended and restated to increase our Three Year Extendible Revolving Credit Facility from $900 million to $1.4 billion, and we established a $350 million Senior Secured Bridge Facility. At the same time we established a $450 million Senior Unsecured Bridge Facility. The terms and conditions of the Three Year Extendible Revolving Credit Facility remained unchanged except for changes to the security pledged and the addition of a 15 basis point fee applicable so long as the $450 million Senior Unsecured Bridge Facility was outstanding. The amounts borrowed under the $450 million Senior Unsecured Bridge Facility bear interest at a floating rate based on bankers’ acceptances plus a range of 230 to 280 basis points depending on Harvest’s financial ratios. Further details on the expanded credit facility and the bridge financing are included under "Liquidity and Capital Resources".

The $17.4 million increase in convertible debenture interest is due to the additional convertible debentures outstanding in the second half of 2005 and outstanding for the full year in 2006, the convertible debentures assumed with our acquisition of Viking and the convertible debentures issued in November 2006 partially offset by conversions of convertible debentures to trust units occurring during the year. A full year of interest expense was incurred on approximately $37.9 million of the remaining balance of the $75 million 6.5% convertible debentures that were issued by Harvest in the third quarter of 2005. Approximately $202.2 million of additional convertible debentures were assumed with the merger with Viking and approximately $379.5 million of additional convertible debentures were issued in November. Although holders of the 9%, 8%, 6.5%, 10.5% and 6.4% convertible debenture series have converted $14.3 million of the convertible debentures into 546,086 trust units, the associated reduction in interest expense is not sufficient to offset the additional interest associated with the more recently issued or assumed convertible debentures. Interest on the convertible debentures is reported based on the effective yield of the debt component of the convertible debentures.

Our U.S. dollar denominated 7 7/8 Senior Notes, which bear interest at 7 7/8%, mature on October 15, 2011 and have an early redemption feature. Interest expense for the year ended December 31, 2006 on these notes has remained relatively consistent with the same period in 2005, with any fluctuations attributed to volatility in the Canadian dollar to U.S. dollar exchange rate.

Included in short and long term interest expense is the amortization of the discount on the senior notes, the accretion on the debt component balance of the convertible debentures to face value at maturity, as well as the amortization of commitment fees and legal costs incurred for our credit and bridge facilities, all totaling $8.4 million for the year ended December 31, 2006. This $3.5 million increase from the $4.9 million expensed in 2005 is due mainly to the increased bank borrowings throughout the year in 2006 as well as the increase in convertible debentures outstanding.

Non-Controlling Interest

The non-controlling interest represents the value attributed to outstanding exchangeable shares of Harvest Operations. The exchangeable shares were originally issued by Harvest Operations as partial consideration for the purchase of a corporate entity in 2004. The exchangeable shares rank equally with the trust units and participate in distributions through an increase in the exchange ratio applied to the exchangeable shares when they are ultimately converted to trust units.

Under the plan of arrangement with Viking, exchangeable shareholders were able to convert their exchangeable shares of Harvest Operations into trust units. As a result 156,067 exchangeable shares were converted from January 1, 2006 to June 19, 2006, leaving a balance of 26,902 outstanding at June 19, 2006 compared to a balance of 182,969 at December 31, 2005.

On March 16, 2006, we announced our intent to exercise our de minimus redemption right on the remaining 26,902 exchangeable shares outstanding. As a result, each redeemed exchangeable share was purchased for a total cash payment of $1.0 million.

The net income attributed to non-controlling interest holders for the year ended December 31, 2006 was a gain of $65,000 compared to an expense of $149,000 for the year ended December 31, 2005.

Currency Exchange Loss

Currency exchange gains and losses are attributed to the changes in the value of the Canadian dollar relative to the U.S. dollar on our U.S. dollar denominated LIBOR bank loans, 7 7/8% Senior Notes, as well as any other U.S. dollar deposits and cash balances. At December 31, 2006, the Canadian dollar weakened slightly as compared to the U.S dollar at December 31, 2005, as a result we incurred an unrealized loss on our senior note of $600,000. In connection with the purchase of the refinery, we incurred U.S. denominated LIBOR bank loans which contributed $23.4 million to the unrealized foreign exchange losses for the year ended December 31, 2006. In addition, we also incurred $1.0 million of unrealized foreign exchange gains on transactions incurred by the refinery and realized losses of $371,000. The refinery is considered a self-sustaining operation with a U.S. dollar functional currency. The foreign exchange gains incurred in the refinery relate to Canadian dollar transactions converted to U.S. dollars as their functional currency is U.S. dollars. Unrealized foreign exchange losses were partially offset by realized gains of $3.2million attributed to gains on the initial deposit of US$100 million for the purchase of North Atlantic and U.S denominated cash and working capital.

Future Income Tax

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

On December 15, 2006, the government announced safe harbour guidance regarding "normal growth" for equity capital. The safe harbour amount will be measured by reference to the individual trust’s market capitalization as of the end of trading on October 31, 2006 (which was approximately $3.7 billion for Harvest). For the period from November 1, 2006 to December 31, 2007 a trust’s safe harbour amount will be 40% of the October 31, 2006 market capitalization benchmark and for each of the years 2008 through and including 2010 will be 20% of the benchmark, cumulatively allowing growth of up to 100% until 2011. In addition, we understand that trusts will be able to issue equity to retire debt existing on October 31, 2006 without eroding their safe harbour limits.

On December 21, 2006, the government released more detailed draft legislation with respect to the proposed amendments to the Income Tax Act and requested comments from stakeholders. In late January 2007, the House of Commons Standing Committee on Finance held special hearings on the proposed tax and the draft legislation. At this time we are unable to determine the impact, if any, these hearings may have on the proposed legislation or the timing of when the proposed legislation could be passed in Parliament.

Should the tax legislation become substantially enacted, future income taxes may be adjusted to include temporary difference between the accounting and tax bases of the Trust’s assets and liabilities. In addition, reserves reported under NI 51-101 maybe adjusted to include an estimate of the tax effect on our estimated future revenues from our reserves. We will assess alternative organizational structures during the four-year transition period, however, we are confident that regardless of the final tax legislation or our structure we will continue to provide value to our unitholders.

During 2006, we have integrated Viking and Birchill into the Harvest organization in such a fashion that much of the value of these acquisitions is attributed to the net profits interests on the respective petroleum and natural gas properties created subsequent to their acquisition. The value of the net profits interest resides within the Trust while the tax basis associated with these acquisitions is retained by our corporate entities. The net result of this approach to integration for income tax purposes is that the book basis and the tax basis of our petroleum and natural gas assets held in corporate entities are approximately equal resulting in no recorded future income taxes beyond the recovery of $2.3 million in the current year. The significant recovery of $32.4 million for the year ended December 31, 2005 is related to net losses for income tax purposes recorded in corporate subsidiaries.

Risk Management Contracts

In connection with the acquisition of North Atlantic we entered into a series of U.S dollar forward purchase contracts to protect a portion of the U.S dollar denominated purchase price from currency exchange rate fluctuations. We realized a gain on these contracts of $17.8 million. No similar arrangements were entered into in 2005. Our total realized loss on price risk management contracts, including those incurred by our petroleum and natural gas operations, are $44.8 million consisting of $76.0 million losses on commodity price risk contracts, $19.6 million gain on currency exchange contracts and $11.6 million gains on electric power fixed price contracts.

Deferred Charges and Other Non-Current Assets

The deferred charges and other non-current assets balance on the balance sheet is comprised of four main components: deferred financing charges, discount on senior notes, long-term leases and for 2005, deferred charges related to the discontinuation of hedge accounting principles. The deferred financing charges relating to the issuance of the senior notes, convertible debentures and bank debt are amortized over the life of the corresponding debt. Other non-current assets include the long-term leases of $3.0 million (net of the current portion of $1.4 million), are related to vehicles provided to the distributors of refined products for the local Newfoundland and Labrador market. These leases are provided under direct financing leases with the majority having terms of 2-5 years. The following table provides a summary of the components of the deferred charges, excluding other non-current assets, at December 31, 2006 as compared to 2005.

	Financing		Discount on		Discontinuation of
(000s)		Costs	Senior Notes		Hedge Accounting			Total
Balance, January 1, 2005	$	12,781	$	2,000	$	10,759	$	25,540
Additions		5,207		-		-		5,207
Transferred to Unit issue costs on conversion of debentures		(2,071)		-		-		(2,071)
Amortization		(4,853)		(296)		(10,759)		(15,908)
Balance, December 31, 2005	$	11,064	$	1,704	$	-	$	12,768
Additions		28,830		-		-		28,830
Transferred to Unit issue costs on conversion of debentures		(193)		-		-		(193)
Amortization		(8,432)		(296)		-		(8,728)
Balance, December 31, 2006	$	31,269	$	1,408	$	-	$	32,677

Additions to deferred financing costs relate to execution of our new credit agreements and costs relating to the issue of our convertible debentured during the year.

At December 31, 2006 our deferred credit balance was $794,000 ($398,000 at December 31, 2005) all of which relates to leasehold improvement costs incurred by us and reimbursed by the landlord. The credit is amortized over the lease term as a reduction of rent expense.

Contractual Obligations and Commitments

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

	Maturity
Annual Contractual Obligations (000s)	Total	Less than 1 year	1-3 years	4-5 years	After 5 years
Long-term debt	1,887,013	-	1,595,663	291,350	-
Interest on long-term debt⁽⁴⁾	299,649	112,037	146,565	41,047	-
Interest on convertible debentures⁽³⁾	264,499	44,247	83,023	79,853	57,376
Operating and premise leases	19,990	6,476	10,845	2,411	258
Capital commitments⁽⁵⁾	37,410	34,530	2,880	-	-
Asset retirement obligations⁽⁶⁾	686,915	12,748	13,058	13,321	647,788
Transportation ⁽⁷⁾	4,738	2,080	2,441	217	-
Purchase commitments	8,215	8,215	-	-	-
Pension contributions	28,077	780	3,345	4,805	19,147
Feedstock commitment	550,230	550,230	-	-	-
Total	3,786,736	771,343	1,857,820	433,004	724,569


(1)	As at December 31, 2006, we had entered into physical and financial contracts for production with average deliveries of approximately 27,480 barrels of oil equivalent per day for 2007, and 5,000 barrels of oil equivalent per day in 2008. We have also entered into financial contracts to minimize our exposure to fluctuating electricity prices. Please see Note 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.
(6)	Represents the undiscounted obligation by period
(7)	Relates to firm transportation commitment on the Nova pipeline.

Off Balance Sheet Arrangements

We also 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.

LIQUIDITY AND CAPITAL RESOURCES

At the end of December 2006, we had total debt and equity capital of $5,556.2 million compared to $1,099.0 million at the end of the prior year. As presented in the following table, the substantial portion of this $4,457.2 million increase is comprised of:

$1,581.8 million additional bank debt related to the acquisition of Birchill and North Atlantic,

The assumption of $202.2 million principal amount of Convertible Unsecured Subordinated Debentures and issuance of 46,040,788 trust units at an ascribed value of $1,638.1 million relating to the acquisition of Viking,

The issuance of 7,026,500 trust units with net proceeds of $218.6 million in connection with the Birchill acquisition and a further 9,499,000 trust units for net proceeds of $610.2 million to refinance the North Atlantic acquisition, and

The issuance of 5,464,917 trust units pursuant to Harvest’s Premium Distribution^TM, Distribution Reinvestment and Optional trust unit Purchase Plan (the "DRIP Plans") raising $167.6 million.

(in million)
	As At December 31
	2006	2005
DEBT
Credit Facilities
- Three Year Extendible Revolving Credit Facility	$1,306.0	$ -
- Senior Secured Credit Facility	289.7	-
- 364 day Extendible Revolving Credit Facility	-	13.9
Total Bank Debt	1,595.7	13.9

7 7/8 % Senior Notes due 2011 (US$250 million)	291.4	290.8

Convertible Debentures, at principal amount
10.5% Debentures Due 2008	26.6	-
9% Debentures Due 2009	1.2	1.8
8% Debentures Due 2009	2.2	3.8
6.5% Debentures Due 2010	37.9	41.4
6.4% Debentures Due 2012	174.8	-
7.25% Debentures Due 2013	379.5	-
Total Convertible Debentures	622.2	47.0

Total Debt	2,509.3	351.7

TRUST UNITS
122,096,172 issued at end of 2006	3,046.9
52,982,567 issued at end of 2005		747.3

TOTAL OF DEBT AND TRUST UNITS	$5,556.2	$1,099.0

Our approach to managing our capital resources is comprised of three objectives: (1) to fund distributions to unitholders and the internal development of our assets from annual Cash Flow; (2) to maintain a sufficient balance sheet strength to continue development activities and acquiring petroleum and natural gas assets to replace production and add reserves; and (3) to permanently fund significant acquisitions with some combination of term debt and equity, such that acquisitions further strengthen our balance sheet capability.

For the year ended December 2006, our Cash Flow totaled $545.2 million ($551.7 million after excluding $6.5 million of one time cash transaction costs relating to the acquisition of Viking) compared to $309.8 million in the prior year. In 2006, we paid distributions to unitholders aggregating to $440.9 million, with $167.5 million reinvested through our DRIP Plans, with $273.4 million remaining to fund our combined $398.3 million capital program. This compares with distributions paid to Unitholders totaling $143.2 million (excluding the $10.7 million special distribution settled with the issue of trust units), with $36.2 million reinvested through the DRIP plans, resulting in $107.0 million to fund $120.5 million of capital spending.

Management, together with the Board of Harvest continually assess distributions relative to cash flow projections, debt leverage and capital spending plans. Distributions declared for 2006 totaled $468.8 million representing 85% of Cash Flow excluding $6.5 million of one time cash transaction costs. Of the distributions declared, $175.8 million have been settled with trust units as a result of Unitholders choosing to participate in our distribution reinvestment plans, representing a participation rate of approximately 38%. On January 10, 2007, we announced the declaration of a $0.38 per trust unit distribution for each of January, February and March 2007 based on forecasted commodity price levels and operating performance that are consistent with the current environment.

Concurrent with the closing to the arrangement with Viking, we entered into a credit agreement establishing a $750 million Three Year Extendible Revolving Credit Facility with improved borrowing margins and more flexible covenant-based terms. On March 31, 2006, this credit agreement was syndicated to a group of thirteen lenders and expanded to $900 million. This bank facility carries floating interest rates that are expected to range between 65 and 115 basis points over bankers’ acceptance rates depending on our secured senior debt (excluding, 7 7/8% Senior Notes and convertible debentures) to earnings before interest, taxes, depletion, amortization and other non-cash amounts ("EBITDA") with availability under this facility subject to:

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

With the consent of the lenders, this facility may be extended on an annual basis for an additional 364 days.

On August 15, 2006, we closed the acquisition of Birchill for cash consideration of $446.8 million and funded this acquisition with the $218.6 million of net proceeds from an issuance of 7,026,500 trust units and $228.2 million of incremental bank borrowings. The results of operations from this acquisition have been included in our consolidated results commencing July 26, 2006, the date of the definitive agreement.

On August 22, 2006, we entered into a purchase and sale agreement to acquire North Atlantic Refining Limited for a total cash consideration of US$1,385 million and provided the vendors with a US$100 million escrowed deposit and on October 19, 2006, closed the transaction. To fund this acquisition, we entered into credit agreements upsizing our Three Year Extendible Revolving Credit Facility to $1.4 billion as well as establishing a $350 million Senior Secured Bridge Facility and a $450 million Senior Unsecured Bridge Facility concurrent with the signing of the purchase and sale agreement. For a complete description of these credit agreements, see Note 10 to our audited consolidated financial statements for the year ended December 31, 2006 filed on SEDAR at www.sedar.com. On August 25, 2006, we entered into contracts to forward purchase US$750 million at a fixed rate of $1.10832 (or $0.9023) to be delivered on October 2, 2006, the then expected closing date of the North Atlantic acquisition. As events unfolded, these forward purchase commitments were rolled forward to October 19, 2006, the ultimate closing date. The intention of these forward purchase contracts was to fix the Canadian dollars required to fund US$750 million of the purchase price at approximately $830 million with the residual US$635 million to be financed with US dollar borrowings. The $830 million represented the expected refinancing from future public equity issuances to be raised in Canadian dollars.

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

to post letters of credit for crude oil feedstock purchase commitments,
arranging for the delivery of crude oil feedstock to the Refinery,
to pay for crude oil feedstock purchases in-transit to the Refinery,
to provide working capital for:
- crude oil feedstock inventories sufficient for stable Refinery operations,
- refined product inventories prior to shipping to market,
- receivables related to the sale of refined products, and
arranging for the delivery of refined products to customers.

The Supply and Offtake Agreement significantly reduces the working capital requirements of North Atlantic as the vessels delivering the crude oil feedstock may carry in excess of 2 million barrels (value approximately - $120 million) and the inventories of refined products and crude oil feedstock at any time may be substantial (currently approximately valued at $400 million). In respect of this working capital requirement assumed by Vitol Refining S.A., the Supply and Offtake Agreement provides that North Atlantic will pay a time value of money charge reflecting an effective interest rate of 350 basis points over the London Inter Bank Offer Rate. The Supply and Offtake Agreement may be terminated by either party at the end of the initial two year term (October 2009), and at any time thereafter by providing notice of termination no later than six months prior to the desired termination date. The potential termination of the Supply and Offtake Agreement requires that we develop the financial flexibility to provide the working capital requirements currently funded by Vitol Refining S.A. as well as either develop the internal capability to provide these supply services for the Refinery or negotiate a similar contract with another provider of such services. At the end of December 31, 2006, we estimate that the outstanding commitments under the Supply and Offtake Agreement aggregated to approximately $550.2 million.

On October 25, 2006, we entered into an agreement with a syndicate of underwriters to issue a $400 million principal amount of 6.30% convertible unsecured subordinated debentures (convertible at $38.50 per trust unit) and 3,150,000 trust units (to be issued at $31.75 per trust unit) for net proceeds, before election of the underwriters’ Over-Allotment Option, of approximately $479 million and on October 31, 2006, filed the preliminary short form prospectus supporting this issuance. Also on that day, the Minister of Finance of the Government of Canada proposed to apply a 31.5% tax at the mutual fund trust level on distributions from certain publicly traded mutual funds which definition includes Harvest Energy Trust and to treat such distributions as dividends to the unitholders (the "October 31, 2006 Proposal"). The announcement of the October 31, 2006 proposal triggered a termination clause in our agreement with the syndicate of underwriters as the proposed change in income tax laws had a significant material adverse effect on the market price of Harvest’s trust units. On October 31, 2006, the Harvest trust units traded between $33.06 and $32.39 closing at $32.95 and on November 1, 2006, traded between $29.90 and $26.80 closing at $28.60 with subsequent days trading trending stabilizing in the $26 to $27 range representing a drop of 18% in trading price.

On November 9, 2006, we amended the terms of our agreement with the syndicate of underwriters to an issuance of $330 million principal amount of 7.25% convertible unsecured subordinated debentures and 8,260,000 trust units for net proceeds, before election of the underwriters’ Over-Allotment Option, of approximately $530 million. On November 22, 2006, this offering closed with $379.5 million principal amount of 7.25% convertible unsecured subordinated debentures (convertible at $32.20 per trust unit) and 9,499,000 trust units (issued at $27.25 per trust unit), which included the underwriters’ election to fully exercise their Over-Allotment Option, for net proceeds of $610.2 million. The impact of the October 31, 2006 Proposal was a $4.50 reduction in the issue price for the trust units and an increase of 0.95% interest rate on the convertible unsecured subordinated debentures as well as a reduction of $6.30 per trust unit in the conversion feature. The net proceeds from this offering were used to fully repay the $450 million of Senior Unsecured Bridge Facility, repay $60.3 million of the Senior Secured Bridge Facility and reduce the drawn portion of its Three Year Extendible Revolving Credit Facility by $99.9 million.

On November 20, 2006, we amended the credit agreement with our lenders to enable the first $100 million of net proceeds on November 22, 2006 to be retained for general corporate purposes to improve our liquidity.

At the end of December 31, 2006, our Bank Debt to Cash Flow ratio was 2.9 to1.0, Total Debt (excluding convertible debentures) to Cash Flow was 3.5 to 1.0 while the Bank Debt to Total Capitalization was 31% and Total Debt to Total Capitalization was 37%.

Subsequent to the end of 2006, we issued 6,146,750 trust units and $230 million principal amount of 7.25% Debenture Due 2014 for net proceeds of $357.4 million. After applying $289.7 million of these proceeds to fully repay the remaining balance outstanding on the $350 million Senior Unsecured Bridge Facility, the residual $67.7 million of proceeds was applied to the $1.4 billion Three Year Extendible Revolving Facility increasing our undrawn credit capacity to approximately $167.1 million

On a pro forma basis reflecting this issuance of $230 million principal amount of 7.25% Debentures Due 2013 and 6,146,750 trust units for net proceeds of $352.8 million, our Bank Debt to Cash Flow ratio would be 2.3 to 1.0 while the Total Debt (excluding convertible debentures) to Total Capitalization would be 30%.

In 2007, we plan extend the maturity date of this credit facility from March 2009 to March 2010 and may consider the issue of additional term debt to replenish the capacity of our term facility.

Disclosure of Outstanding Trust Unit Data

We are authorized to issue an unlimited number of trust units. As at March 12, 2007, we had 129,470,352 number of trust units outstanding, 3,800,675 of Unit Appreciation Rights outstanding (of which 538,550 are exercisable) and 274,384 number of awards issued under the Unit Awards Incentive Plan (of which 93,945 were exercisable). In addition we had seven series of convertible debentures outstanding that are convertible into 26,382,215 trust units.

Distributions to Unitholders and Taxability

In the year ended December 31, 2006, we declared distributions of $4.53 per trust unit ($468.8 million) to Unitholders. This represents a 42% increase in distributions declared over the $3.20 per trust unit declared in 2005. The aggregate distributions declared during 2006 of $468.8 million reflects an increase in distributions on a per-trust unit basis over 2005 as well as an increase in the number of trust units outstanding of 69,113,605 trust units to 122,096,172 following the acquisition of North Atlantic Refining, Viking and Birchill and continued DRIP participation.

		Year end December 31
(000s except per trust unit amounts)		2006		2005	Change
Distributions declared	$	468,787	$	153,494	205%
Per trust unit	$	4.53	$	3.20	42%
Taxability of distributions (%)		100%		100%	-
Per trust unit	$	4.53	$	3.20	42%
Payout ratio (%)⁽¹⁾		85%		50%	35%

(1) Cash flow used to calculate payout ratio excludes working capital changes, settlements of asset retirement obligations and one time transaction costs associated with the Viking acquisition see Non-GAAP measures.

The Trust is subject to tax on its taxable income less the portion that is paid or payable to the Unitholders at the end of each taxation year. As such, we expect that the current year distributions to our Unitholders will be 100% taxable.

OUTLOOK

Unitholders should benefit from the addition of the North Atlantic refining and marketing business to our petroleum and natural gas operations in western Canada with distributions funded by a more diversified cash flow. Refining is primarily a margin business where the crude oil feedstocks and refined products are both commodities which react to differing regional supply/demand and transportation pressures. Accordingly, refining margins should not be as sensitive to changes in commodity prices as our petroleum and natural gas operations, however, the demand for refined products is also a contributor to the general level of global crude oil prices. We anticipate that increases in heavy oil price differentials will have a favourable impact on our refining margins while the price realizations of our petroleum and natural gas operations in western Canada will suffer: this internal and offsetting impact should result in a more stable Cash Flow.

The following summarizes our 2007 guidance relative to its 2006 performance. There is no attempt to forecast commodity prices and accordingly do not forecast Cash Flow or the level of cash distributions. This 2007 guidance includes the modest impact of our acquisition of Reveal Resources Ltd. for $29.9 million of cash consideration. Reveal’s production consists of approximately 1,600 boe/d of primarily heavy oil in west central Saskatchewan.

	2007 Forecast	2006
Petroleum and Natural Gas Operations
Average Production in boe/d	66,000	59,729

Operating Costs in $/boe	$10.70	$10.59

Average Royalty Rate	19%	18%

Production mix
Light/medium oil in bbls/d	28,000	27,482
Heavy oil in bbls/d	16,800	13,904
Natural gas in mcf/d	112,000	96,578
Natural gas liquids in bbls/d	2,700	2,247

Capital expenditures (in millions)⁽¹⁾	$295	$377

Refining and Marketing
Throughput in bbls/d	116,100	n/a

Operating costs in $/bbl, including purchased energy	$4.40-4.60	n/a

Capital expenditure (in millions)	$60	n/a

Payout Ratio	55% to 80%	85%

(1) 2007 reflects the acceleration of $20 million of 2007 capital into 2006.

At the end of 2006, we had entered into price risk management contracts to provide a floor price of approximately US$56 (relative to the West Intermediate Texas benchmark price) on 27,500 bbls/d throughout 2007 with upside participation in prices higher than US$56. After considering our 19% average royalty rate, these risk management contracts reduce our WTI price risk exposure at prices under US$56 to 25% of our crude oil production. This significantly reduces the volatility of our cash flows to WTI prices if prices trend below the US$56 price level. To complement these price risk management contracts, we have forward sold US$8,750,000 per month at an average Canadian dollar to US dollar exchange rate of approximately US$0.89 per Canadian dollar through December 2007 and a further US$8,333,000 per month at US$0.90 per Canadian dollar for the first half of 2008, which represents approximately 20% of the US dollar value of the crude oil price risk management contracts.

At the end of 2006, we had entered into price risk management contracts to collar AECO based natural gas prices on 50,000 GJ/d with an average floor price of $6.00 and an average price cap of $13.00 for the period through March 2007. In early 2007, we added contracts that provided the following three way price structure on 30,000 GJ/d for the period from April 2007 through March 2008:

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

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

In addition, we have also entered in to contracts to fix the price of 35 megawatthours (or approximately 50% of the anticipated electrical consumption of its petroleum and natural gas operations in Alberta) through to the end of December 2008 at price of $56.69. Our objective with these fixed price contracts is to substantially reduce the volatility of our operating costs to fluctuations in cost of electricity which represent approximately 25% of the operating costs in our petroleum and natural gas operations.

We are currently evaluating the impact of the North Atlantic acquisition on our overall corporate risk management profile with a goal of adding stability to our ability to fund sustainable cash distributions in a wide variety of pricing environments. Currently, the most likely outcome appears to be that we will commence contracting for price protection on refined products (rather than crude oil prices) and continue to contract for protection on AECO natural gas prices and the currency exchange rate for US dollars to Canadian dollars along with a measured approach to negotiating fixed prices for electricity.

Our growth strategies for the petroleum and natural gas operations in western Canada will be to continue to acquire properties immediately adjacent to our existing operations on favourable terms as well as develop our extensive resource position with a 2007 capital spending plan of $295 million. While down from $376.9 million in 2006, the 2007 capital plan reflects the acceleration of $20 million of 2007 planned activity forward to December 2006 at Hay River and Red Earth due to favourable weather conditions. In our refining and marketing business for 2007, we expect to invest approximately $30 million in maintenance capital with discretionary capital spending ranging from $15 million to $30 million for a visbreaker unit upgrade as well as other discretionary projects. The visbreaker project will enable a further upgrading of approximately 1,500 bbl/d of heavy fuel oil to higher valued refined products with an on-stream date during the fourth quarter of 2008 expected. In addition, we intend to be an active participant in the consolidation of Canadian energy royalty trusts which is dependent on the currency value of our trust units as trust-on-trust mergers are expected to be negotiated based on market valuations with premiums, if any, being nominal.

Following the announcement by the Minister of Finance for the Government of Canada on October 31, 2006 to apply a 31.5% tax at the mutual fund trust level on distributions of certain income from publicly traded mutual fund trusts including Harvest Energy Trust, we will continue to explore the most efficient capital structure for its Unitholders balancing the benefits of the remaining four years of tax efficient distributions against the longer term benefits of continuing with a growth strategy beyond the "normal growth." At this time, the absence of firm guidelines and proposed Tax Act changes limits our ability to properly evaluate alternative structures and future plans.

The following table reflects sensitivities of our expected 2007 Cash Flow to the key economic drivers of our business:


		Assumption		Change	Impact on Cash Flow
WTI oil price ($US/bbl)	$	60.00	$	5.00	$	0.37 / Unit
CAD/USD exchange rate	$	0.90	$	0.05	$	0.54 / Unit
AECO daily natural gas price	$	7.00	$	1.00	$	0.26 / Unit
Refinery crack spread (US$/bbl)	$	9.30	$	1.00	$	0.34 / Unit
Operating Expenses (per boe)	$	10.65	$	1.00	$	0.18 / Unit

For Canadian income tax purposes, unitholders should anticipate that our distributions will continue to be 100% taxable with no "return of capital."

SUMMARY OF FOURTH QUARTER RESULTS

	Three months ended December 31
	Petroleum	Refining
	and natural	and
	gas 2006	marketing	Total
		2006	2006	2005	Change

Revenues	273,110	460,359	733,469	185,824	295%
Royalties	(50,725)	-	(50,725)	(31,178)	63%
Realized losses on risk management contracts⁽³⁾	(12,506)	-	(12,506)	(13,233)	(5%)
Unrealized gains on risk management contracts	16,213	-	16,213	28,463	(43%)
Net revenues	226,092	460,359	686,451	169,876	304%

Purchased product for resale and processing	-	386,014	386,014	-	n/a

Operating expenses	69,298	34,063	103,361	38,736	167%
Realized gains on electric power hedge	(6,510)	-	(6,510)	(4,507)	44%
Net operating expenses	62,788	34,063	96,851	34,229	183%

General and administrative expenses	6,714	-	6,714	4,083	19%
Less: Unit based compensation expenses	(167)	-	(167)	1,568	(89%)
Total cash general and administrative expenses	6,547	-	6,547	5,651	60%

Transportation and marketing	2,919	5,060	7,979	98	8,042%
Depreciation, depletion and accretion	116,262	15,482	131,744	51,012	158%
Net income per segment	37,576	19,740	57,316	78,886	(27%)
Interest expense			41,184	8,499	385%
Corporate costs⁽⁴⁾			14,599	(5,251)	(378%)
Net income			1,533	75,638	(98%)

Payout ratio			86%	57%	37%

Cash capital asset additions (excluding acquisitions)	90,358	21,411	111,769	39,476	183%

Refinery Throughput (mbbl)	-	6,343	6,343	-	n/a

OPERATING
Daily sales volumes
Light / medium oil (bbl/d)	28,152			20,471	38%
Heavy oil (bbl/d)	13,967			13,273	5%
Natural gas liquids (bbl/d)	2,649			867	205%
Natural gas (mcf/d)	112,006			25,339	342%
	63,436			38,834	63%

OPERATING NETBACK⁽¹⁾ ($/BOE)
Revenue	46.80			52.01	(10%)
Realized loss on risk management contracts	(2.14)			(3.70)	(42%)
Royalties as percent of revenue	(8.69)			(8.73)	-
As a percent of revenue	18.6%			16.8%	2%
Operating expense⁽²⁾	(10.76)			(9.58)	12%
Transportation expense	(0.50)			(0.03)	4467%
Operating Netback⁽¹⁾	24.71			29.97	(18%)

(1) This is a non-GAAP measure, please refer to "Non-GAAP Measure" in this MD&A.

(2) Includes realized gain on electricity risk management contract of $1.12/BOE and $1.26/BOE for the three months ended December 31, 2006 and 2005 respectively.

(3) Includes amounts realized on WTI, heavy oil price differential and currency exchange contracts and excludes amounts realized on electricity contracts and amounts realized on the series of US dollar forward purchase contracts entered into with respect to the purchase of North Atlantic.

(4) 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

Our 2006 fourth quarter is not directly comparable to our 2005 fourth quarter as a result of the acquisition of the refinery during the fourth quarter of 2006. As a result it is more applicable to compare our petroleum and natural gas segment fourth quarter results to our 2005 fourth quarter results. Results of our refining and marketing division have been discussed in other sections of our MD&A.

Our 2006 fourth quarter revenues have increased over the fourth quarter in 2005 as a result of increased production volumes due to the Viking and Birchill acquisitions and higher heavy oil prices, these increases were partially offset by lower gas and light to medium oil prices during the fourth quarter. Light / medium oil sales revenue for the three month period ended December 31, 2006 was $31.3 million (or 29%) higher than in same period in the prior year due to a favourable volume variance of $40.7 million and an unfavourable price variance of $9.4 million. Heavy oil revenues for the three months ended December 31, 2006 increased by $2.2 million (or 5%) due to an unfavourable price variance of $0.2 million and a favourable volume variance of $2.4 million. Natural gas sales revenue increased by $45.5 million (or 171%) for the three months ended December 31, 2006 over the same period in 2005, which reflects a favourable volume variance of $90.8 million and an unfavourable price variance of $45.3 million. The increase in our natural gas volumes are related to the acquisition of Viking which significantly increased our natural gas production as well as the acquisition of Birchill, which was predominantly gas. During 2006, natural gas prices were relatively weaker than in 2005 resulting in a significant unfavourable price variance.

Our fourth quarter 2006 production volumes are higher than in 2005 as production in the fourth quarter of 2006 reflects a full quarter of production from Viking and Birchill as well as added production from our drilling activity in the year.

For the three months ended December 31, 2006, our net royalties as a percentage of revenue were 18.6% ($50.7 million), compared to 16.8% ($31.2 million) in the same period in 2005. This increase in the royalty rate is mainly due to higher royalty rates associated with the Viking acquisition.

Operating expenses increased by $64.6 million (or 167%) for the three months ended December 31, 2006 compared to the same period in the prior year. Of this increase, $27.2 million relates to the acquisition of Viking, $34.1 million relates to the acquisition of the refinery, while the remaining increase reflects inflationary cost pressures in the Western Canadian oil and natural gas sector.

For the three months ended December 31, 2006, Cash G&A increased by $0.9 million (or 122%) compared to the same period in the prior year. This increase is reflective of additional staffing costs relating to the Viking acquisition and generally higher costs for our external service providers.

Interest expense increased by $32.7 million for the three months ended December 31, 2006 relative to the same period in the prior year due to the acquisition of the refinery, which was initially financed with debt resulting in a significantly higher average debt balances on the credit facility in 2006.

After capital spending of $103.2 million, $54.2 million, and $129.1 million in the first, second and third quarters of 2006, respectively, capital spending in our petroleum and natural gas segment totaled $90.4 million including approximately $20 million of capital accelerated from the 2007 capital plan to take advantage of favourable weather conditions at our Hay River and Red Earth operations.

SUMMARY OF HISTORICAL QUARTERLY RESULTS

The table and discussion below highlight our fourth quarter 2006 performance over the preceding seven quarters on select measures.

Financial		2006								2005
($000s except where noted)		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Revenue, net of royalties		682,744	$	259,818	$	257,103	$	181,160	$	154,646	$	169,654	$	120,263	$	109,931
Net income (loss)		1,533		107,768		60,682		(33,937)		75,638		52,862		19,516		(43,070)
Per trust unit, basic²	$	0.01	$	1.01	$	0.60	$	(0.41)	$	1.45	$	1.09	$	0.45	$	(1.02)
Per trust unit, diluted²	$	0.01	$	0.99	$	0.60	$	(0.41)	$	1.42	$	1.08	$	0.44	$	(1.02)
Cash Flows¹		156,270		147,471		147,010		100,971		96,431		103,508		57,217		52,687
Per trust unit, basic¹	$	1.35	$	1.39	$	1.45	$	1.23	$	1.84	$	2.14	$	1.32	$	1.25
Per trust unit, diluted¹	$	1.29	$	1.34	$	1.43	$	1.22	$	1.81	$	2.09	$	1.29	$	1.19

Distributions per Unit, declared		1.14	$	1.14	$	1.14	$	1.11	$	1.05	$	0.95	$	0.60	$	0.60
Total long term financial liabilities		2,478,518		1,105,728		746,840		735,896		349,074		386,124		455,163		321,534
Total assets		5,745,558		4,076,771		3,455,918		3,470,653		1,308,481		1,327,272	1,117,792			1,079,269
Total production (boe/d)		63,436		62,178		60,145		53,014		38,834		37,549		34,463		35,386

(1) This is a non-GAAP measure as referred to under "Non-GAAP Measures".

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

Net revenues and Cash Flows have generally increased steadily over the eight quarters as shown above. The significantly higher revenue in the second and third quarter of 2006 over the preceding quarters is due to the incremental revenue recorded from the Viking assets acquired in February of 2006 and a rising commodity price environment. In the fourth quarter of 2006, another significant increase in revenue is realized due to the acquisition of the refinery which will result in significantly higher revenues in this quarter and future quarters.

Cash flows have also steadily risen over the same period, with marked increases in the second and third quarter of 2006 due to strong commodity prices, narrower heavy oil differentials and the realization of the full benefits of the merger with Viking on our Cash Flows and another increase in the fourth quarter of 2006 reflecting the additional cash contribution from the North Atlantic acquisition. We also experienced an increased in Cash Flows in the third quarter of 2005 when we benefited from higher production from the Hay River acquisition, stronger crude oil prices and narrower heavy oil differentials early in the quarter. However, this trend did not continue into the fourth quarter of 2005 as a result of decreased commodity prices, and widening heavy oil differentials, which continued into the first quarter of 2006 and also impacted Cash Flows. In the second and third quarters of 2006, Cash Flows were positively impacted by higher commodity prices, lower heavy oil differentials and a full quarter of production from the Viking Energy Royalty Trust assets acquired in February of 2006. The most significant increases in revenue occurred between the first and second quarter of 2006, due to unprecedented commodity prices and the impact of the Viking acquisition that occurred in the first quarter. The general increasing revenue trend since the third quarter of 2004 is also attributable to the strong commodity price environment through 2005 and into 2006.

Net income reflects both cash and non-cash items. Changes in non-cash items, including depletion, depreciation and accretion (DD&A) expense, unrealized foreign exchange gains and losses, unrealized gains and losses on risk management contracts, trust unit right compensation expense and future income taxes can cause net income to vary significantly from period to period. However, these items do not impact the Cash Flows available for distribution to Unitholders, and therefore we believe net income to be a less meaningful measure of performance for us. The main reason for the volatility in net income (loss) between quarters in 2005 and 2006 is due to the changes in the fair value of our risk management contracts. We ceased using hedge accounting for all of our risk management contracts in October 2004 and switched to a fair value accounting methodology, which has substantially increased the volatility in our reported earnings. Due primarily to the inclusion of unrealized mark-to-market gains and losses on risk management contracts, net income (loss) has not reflected the same trend as net revenues or Cash Flows.

CRITICAL ACCOUNTING ESTIMATES

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

Reserves

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

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

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

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

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

Asset Retirement Obligations

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

Impairment of Capital Assets

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

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

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

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

Any impairment charges would reduce our net income.

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

Employee Future Benefits

We maintain a defined pension plan related to employees of the refinery. Obligations under employee future benefits plans are recorded net of plan assets where applicable. An independent actuary determines the costs of our employee future benefits 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 benefits plans could increase or decrease if there were to be a change in these estimates. Pension expense represented less than 0.5% of our total expenses for 2006.

Purchase Price Allocations

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

RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

Convergence of Canadian GAAP with International Financial Reporting Standards

In 2006, Canada’s Accounting Standards Board ratified a strategic plan that will result in Canadian GAAP, as used by public companies, being converged with International Financial Reporting Standards over a transitional period. The Accounting Standards Board is expected to develop and publish a detailed implementation plan with a transition period expected to be approximately five years. This convergence initiative is in its early stages as of the date of these annual consolidated financial statements and the Company has the option to adopt U.S. GAAP at any time prior to the expected conversion date. Accordingly, it would be premature to assess the impact of the initiative, if any, on our financial statements at this time.

Financial Instruments, Comprehensive Income and Hedges

The Accounting Standards Board (AcSB) has issued five new accounting standards relating to the recognition, measurement, disclosure and presentation of financial instruments. The new standards comprise five handbook sections:

CICA Section 3855 – Financial Instruments – Recognition and Measurement

This standard establishes the criteria for recognizing and measuring financial assets, financial liabilities and nonfinancial derivatives. It also specifies how financial instrument gains and losses are to be presented. Financial liabilities will be classified as either held-for-trading or other. Held-for-trading instruments will be recorded at fair value with realized and unrealized gains and losses reported in net income. Other instruments will be accounted for at amortized cost with gains and losses reported in net income in the period that the liability is derecognized.

Derivatives will be classified as held-for-trading unless designated as hedging instruments. All derivatives, including embedded derivatives that must be separately accounted for, will be recorded at fair value on the consolidated balance sheet. For derivatives that hedge the changes in fair value of an asset or liability, changes in the derivatives’ fair value will be reported in net income and be substantially offset by changes in the fair value of the hedged asset or liability attributable to the risk being hedged. For derivatives that hedge variability in cash flows, the effective portion of the changes in the derivatives’ fair value will be initially recognized in other comprehensive income and the ineffective portion will be recorded in net income. The amounts temporarily recorded in other comprehensive income will subsequently be reclassified to net income in the periods when net income is affected by the variability in the cash flows of the hedged item.

CICA Section 3865 – Hedges

This standard provides optional alternative treatment to Section 3855 for entities which choose to designate qualifying transactions as hedges for accounting purposes. It will replace Accounting Guideline 13 (AcG 13) – Hedging Relationships, and build on Section 1560 – Foreign Currency Translation, by specifying how hedge accounting is applied and what disclosures are necessary when it is applied. Retroactive application of this Section is not permitted.

CICA Section 1530 – Comprehensive Income

This standard introduces a new requirement to temporarily present certain gains and losses as part of a new earnings measurement called comprehensive income.

CICA 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.

CICA 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.

CICA sections 3855, 3865 and 1530 are effective for annual and interim periods in fiscal years beginning on or after October 1, 2006. A presentation reclassification of amounts previously recorded in "Foreign currency translation Adjustment" to "Accumulated other comprehensive income" will be made upon adoption of Section 1530. In addition, deferred charges associated with the bank debt will be expensed and those incurred related to convertible debentures and the 7 7/8% Senior Notes will be recorded net of the debt balance. We do not expect there to be any other material impact on the Consolidated Financial Statements upon adoption of the new standards.

CICA sections 3862 and 3863 are effective for annual and interim periods beginning on or after October 1, 2007.

Accounting changes

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

Variable Interest Entities

The Emerging Issues Committee (EIC) issued EIC Abstract 163 – Determining the Variability to be Considered in Applying AcG 15. This Abstract, which is harmonized with the equivalent United States FASB Staff Position (FSP) FIN 46(R) – 6 – Determining the Variability to be Considered in Applying FASB Interpretation No. 46(R), provides guidance on how an enterprise should determine the variability to be considered in applying AcG 15 – Consolidation of Variable Interest Entities. The Abstract is to be applied prospectively to all entities with which an enterprise first becomes involved and to all entities previously required to be analyzed under AcG 15 when a reconsideration event has occurred beginning the first day of the first reporting period beginning on or after January 1, 2007.

OPERATIONAL AND OTHER BUSINESS RISKS

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

Operation of oil and natural gas properties:

Applying a proactive management approach to our properties;

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

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

Operation of a refining and petroleum marketing business

Maintaining a proactive approach to managing the Supply and Offtake Agreement 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 unionized work force to minimize operational disruptions due to strikes or work stoppages; and
Selectively adding experienced refining management to strengthen our "in-house" management team, particularly a new leader for our refinery operations to replace the current President , Refinery Manager of North Atlantic who has committed to an orderly transition.

Estimates of the quantity of recoverable reserves:

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

Commodity price exposures:

Maintaining a risk-management policy and committee to continuously review effectiveness of existing actions, identify new or developing issues and devise and recommend to the Board of Directors of Harvest Operations action to be taken;
Executing risk management contracts with a portfolio of credit-worthy counterparties;
Maintaining a low cost structure to maximize product netbacks; and
Limiting the period of exposure to price fluctuations between crude oil prices and products 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 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.

Disruptions in the supply of crude oil and delivery of refined products:

We have entered into a supply and offtake agreement with Vitol Refining S.A., a subsidiary of Vitol Refining Group B.V, one of the world’s larges physical traders and marketers of crude oil and petroleum products so to minimize the risk of disruptions in supply.

Employee relations:

A significant proportion of the employees of the refinery are unionized and resources are allocated to assist in maintaining good relations with the union to minimize operations disruptions due to strikes or work stoppage.

Non-GAAP Measures

Throughout this MD&A we have referred to certain measures of financial performance that are not specifically defined under Canadian GAAP. Specifically, we use Cash Flow as cash flow from operating activities before changes in non-cash working capital, settlement of asset retirement obligations and one time transaction costs. Cash Flow as presented is not intended to represent an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with Canadian GAAP. Management uses Cash Flow to analyze operating performance and leverage. Payout Ratio, Cash G&A and Operating Netbacks are additional non-GAAP measures used extensively in the Canadian energy trust sector for comparative purposes. Payout Ratio is the ratio of distributions to total Cash Flow. Operating Netbacks are always reported on a per boe basis, and include gross revenue, royalties and operating expenses, net of any realized gains and losses on related risk managements. Cash G&A are G&A expenses excluding the effect of our unit based compensation plans. Gross Margin is commonly used in the refining industry to reflect the net cash received from the sale of refined products after considering the cost to purchase the feedstock and is calculated by deducting purchased products for resale and processing from total revenue. Operating income is also commonly used in the petroleum and natural gas and in the refining industry to reflect operating results before items not directly related to operations.

For the three and twelve months ended December 31, 2006 and 2005, Cash Flows are reconciled to its closest GAAP measure, Cash Flow from operating activities, as follows:

	Three months ended December 31				Year ended December 31
($000s)		2006		2005		2006		2005

Cash Flow	$	156,270	$	96,431	$	551,724	$	309,843
Cash Viking transaction costs		(243)		-		(6,501)		-
Settlement of asset retirement obligations		(5,158)		(1,813)		(9,186)		(4,146)
Changes in non-cash working capital		(10,327)		3,348		(28,152)		(22,519)
Cash flow from operating activities		140,542	$	97,966		507,885	$	283,178

Disclosure Controls and Procedures

Under the supervision of our Chief Executive Office and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures as of the end of December 31, 2006 as defined under the rules adopted by the Canadian securities regulatory authorities and by the U.S. Securities and Exchange Commission. On October 19, 2006, we acquired North Atlantic and our evaluation of disclosure controls and procedures was expanded to include a review of their design and effectiveness.

Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that as of the end of the fiscal year, the design and operation of our disclosure controls and procedures were effective to ensure that information required to be disclosed by Harvest in reports it files or submits under Canadian and US securities regulatory authorities was recorded, processed, summarized and reported within the time periods specified in Canadian and US Security 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 disclosure.

Internal Controls Over Financial Reporting

Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with Generally Accepted Accounting Principles. On October 19, 2006, we acquired North Atlantic and expanded our review of internal control over financial reporting to include the review of the design of North Atlantic’s controls over their internal reporting of financial information. Our evaluation of the design and effectiveness of our internal control over financial reporting as of the end of December 31, 2006 was based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). There were no changes in our internal controls over financial reporting during the year ending December 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We have completed our review of the design of North Atlantic’s control over their internal reporting of financial information but have not completed an evaluation as to its effectiveness which is planned to be completed in 2007. North Atlantic’s total assets, net sales and earnings before interest expense and income taxes constitute 30%, 29% and 9% of Harvest’s consolidated total assets, net sales and income, respectively, as of and for the fiscal year ended December 31, 2006.

Based on our evaluation which was completed under the supervision of our Chief Executive Officer and Chief Financial Officer, we have concluded that as of December 31, 2006, we had effective controls over financial reporting. This conclusion excludes an evaluation of North Atlantic’s control over their internal reporting of financial information.

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

Forward-Looking Information

This MD&A highlights significant business results and statistics from our consolidated financial statements for year ended December 31, 2006 and the accompanying notes thereto. In the interest of providing our Unitholders and potential investors with information regarding Harvest, including our assessment of our future plans and operations, this MD&A contains forward-looking statements that involve risks and uncertainties. Such risks and uncertainties include, but are not limited to, risks associated with conventional petroleum and natural gas operations; risks associated with refinery operations, the volatility in commodity prices and currency exchange rates; risks associated with realizing the value of acquisitions; general economic, market and business conditions; changes in environmental legislation and regulations; the availability of sufficient capital from internal and external sources and such other risks and uncertainties described from time to time in our regulatory reports and filings made with securities regulators.

Forward-looking statements in this MD&A include, but are not limited to, production volumes, refinery throughput volumes, royalty rates, operating costs, commodity prices, administrative costs, commodity price risk management activity, acquisitions and dispositions, capital spending, reserve estimates, distributions, access to credit facilities, capital taxes, income taxes, Cash Flow From Operations and regulatory changes. For this purpose, any statements that are contained herein that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements often contain terms such as "may", "will", "should", "anticipate", "expects", and similar expressions.

Readers are cautioned not to place undue reliance on forward-looking statements as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. Although we consider such information reasonable, at the time of preparation, it may prove to be incorrect and actual results may differ materially from those anticipated. We assume no obligation to update forward-looking statements should circumstances or estimates or opinions change except as required by law. Forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

Additional Information

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

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