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

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") of the financial condition and results of operations of Harvest Energy Trust should be read in conjunction with our audited consolidated financial statements and accompanying notes for the years ended December 31, 2005 and 2004 as well as our unaudited consolidated financial statements and notes for the three and nine month periods ended September 30, 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 November 8, 2006.

When reviewing our 2006 results and comparing them to 2005, readers are cautioned that the 2006 results include three full quarters of operations from our Hay River acquisition in the August 2005, only eight months of operations from our acquisition of Viking in February 2006, and only two months of operations from the Birchill Energy Limited ("Birchill") acquisition in August 2006. The combination of these events significantly impacts the comparability of our operations and financial results for 2006 to the results of the same period of 2005. To increase comparability, in certain instances, we have provided financial information for the second quarter of 2006, which reflects the results of operations of Harvest including a full three months of results of Viking and Hay River.

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 (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.

Financial and Operating Highlights – Third Quarter 2006

• Cash Flows of $147.5 million for the third quarter in 2006 is relatively unchanged from the $147.0 million Cash Flow reported in the second quarter of 2006 and a 42% increase over the $103.5 million earned in the third quarter of 2005. Cash distributions declared totaled $1.14 per trust unit in both the third quarter and the second quarter of 2006 representing a payout ratio of 83% and 79%, respectively.

• Production of 62,178 boe per day (boe/d) for the third quarter, an increase in average daily production of 3% over the 60,145 boe/d reported in the second quarter of 2006 despite a temporary reduction in the third quarter related to downtime in a non-operated gas processing facility.

• Third quarter capital reinvestment of $129.1 million brings the total for year to $286.5 million. In the third quarter, 76 gross wells (60 net) were drilled resulting in 74 gross (58.3 net) successful wells with total wells drilled in 2006 totaling 195 gross (152.7 net) of which 191 gross (150.0 net) were successful.

• During the third quarter of 2006, we announced an agreement to acquire an 115,000 barrel per stream day refinery located in the Province of Newfoundland and Labrador for $1.6 billion as well as an expansion of our credit facilities to $2.2 billion, including bridge financing, to fund the acquisition. The refinery processes medium gravity sour crude and produces primarily gasoline, low sulphur diesel and jet fuel the majority of which is sold into premium markets in the United States.

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• Subsequent to the end of the Third Quarter our refinery acquisition was completed and we announced a "bought deal" financing to sell $400 million of convertible debentures and 3,150,000 trust units at a price of $31.75 per trust unit. 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. Currently, we are in discussions with our underwriters and are assessing various alternatives to proceed with this financing. The long term impact of the changes announced by the Government of Canada is being evaluated internally as well as through our active participation in the recently created coalition of Canadian energy trusts.

The table below provides a summary of our financial and operating results for the three and nine month periods ended September 30, 2006 and September 30, 2005. Detailed commentary on individual items within this table is provided elsewhere in this MD&A.

	Three months ended							Nine months ended
							2006 to
FINANCIAL ($000s except							2005				Year over
where noted)	Sept. 30,		June 30,			Sept. 30,	Quarter	Sept. 30,			Sept. 30,	Year
		2006		2006		2005	Change		2006		2005	Change
Revenue, net(1)		312,864	233,128			143,524	118%	677,424			262,069	158%
Cash Flow(2)		147,471	147,010			103,508	42%	395,452			213,412	85%
Per trust unit, basic(2)	$	1.39	$	1.45	$	2.14	(35%)	$	4.09	$	4.78	(14%)
Per trust unit, diluted(2)	$	1.34	$	1.43	$	2.09	(36%)	$	3.94	$	4.55	(13%)
Net income (loss)		107,768		60,682		52,862	104%	134,513			29,308	359%
Per trust unit, basic	$	1.01	$	0.60	$	1.09	(7%)	$	1.39	$	0.66	111%
Per trust unit, diluted	$	0.99	$	0.60	$	1.08	(8%)	$	1.38	$	0.64	116%
Distributions declared		123,112	115,889			46,691	164%	333,813			108,957	206%
Distributions declared, per trust
unit	$	1.14	$	1.14	$	0.95	20%	$	3.39	$	2.15	58%
Payout ratio(2)(3)		83%		79%		45%	38%		84%		46%	38%
Cash capital asset additions
(excluding acquisitions)		129,054		54,230		31,655	308%	286,523			81,032	254%
Bank debt		591,189	227,554			34,649	1,606%	591,189			34,649	1,606%
Production
Light to medium oil (bbl/d)		28,394		28,951		18,868	50%		27,136		16,618	63%
Heavy oil (bbl/d)		13,919		13,037		13,735	1%		14,003		13,906	1%
Natural gas liquids (bbl/d)		2,595		2,016		850	205%		2,111		810	161%
Natural gas (mcf/d)		103,618		96,848		24,574	322%		91,379		26,839	240%
Total daily sales volumes
(boe/day)		62,178		60,145		37,549	66%		58,480		35,807	63%
(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.

Review of Operations and Strategy

The third quarter of 2006 reflects the full impact of the acquisition of Viking Energy Royalty Trust acquired on February 3, 2006 and two months of activity from the Birchill acquisition in August 2006. A strong crude oil and heavy oil differential pricing environment benefited our Cash Flows during the quarter, despite relative weakness in natural gas prices. We generated Cash Flows of $147.5 million ($1.39 per basic trust unit) in the third quarter of 2006, compared to $103.5 million ($2.14 per basic trust unit) in the same period in 2005. This $44.0 million increase in Cash Flow is substantially attributed to the incremental impact of the Viking acquisition on our cash flows but has been partially offset by the trend of rising cost pressures in the oil and natural gas service sector.

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Distributions declared during the quarter totaled $1.14 per trust unit, for a payout ratio of 83%. Distributions were consistent with those declared in the second quarter of 2006 with a slight increase in the payout ratio which was 79% for the second quarter of 2006. Per trust unit distributions are 20% higher compared to the $0.95 per trust unit declared in the third quarter of 2005. 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.

Production was 62,178 boe/d, an increase of 3.4% over second quarter of 2006. This increase is attributed to the Birchill acquisition during the quarter which was partially offset by lower production 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. We are maintaining our forecast for annual production of approximately 60,000 boe/d and an exit production of approximately 66,000 boe/d for the year ended December 31, 2006.

During the third quarter, we invested $129.1 million in our properties, an increase of 308% over the same period in 2005. On a year to date basis, excluding acquisitions, we have invested $286.5 million which is 254% greater than in 2005. Our ability to implement a significantly larger capital program in 2006 reflects our larger size and greater opportunity portfolio. Of the total capital spent, 64% was allocated to drilling and equipping activities. In the third quarter, we drilled 17 net wells in SE Saskatchewan, 8.5 net wells in Hayter, 7 net wells in Suffield, 6 net wells in Lloydminster, 1.6 net wells in Red Earth and 2.8 net wells in Markerville, with a 97% success rate.

For the third quarter of 2006, we closed our acquisition of Birchill for $452.3 million, including working capital adjustments. At the time of acquisition Birchill was providing approximately 6,300 boe/d of production weighted to natural gas, and proved plus probable (P+P) reserves of approximately 22.6 mmboe. This acquisition was accretive to cash flow per unit, reserves per unit and production per unit, and increased Harvest's Reserve Life Index (RLI) to 9.5 years. The acquisition has been financed with a combination of bank debt and the net proceeds from our issuance of 6,110,000 trust units (7,026,500 trust units including over-allotment option) at a price of $32.75 per trust unit in August 2006.

During the third quarter of 2006, we announced an agreement to acquire an 115,000 barrel per stream day refinery located in the Province of Newfoundland and Labrador for US$1.4 billion and an expansion of our credit facilities to $2.2 billion, including bridge financing, to fund the acquisition. On August 23, 2006, we placed $111.3 million in escrow as a performance deposit in respect of our refinery acquisition. The hydrocracking refinery processes medium gravity sour crude oil to gasoline, low sulphur diesel and jet fuel the majority of which are sold into premium markets in the United States. Its strategic position along the major Atlantic Ocean shipping routes has several advantages. We are in close proximity to feedstock sources such as Middle East, Latin America or Russia and also have ready access to large markets for refined products in northeastern United States. As a result, the refinery offers attractive operating economics. We closed our refinery acquisition on October 19, 2006 and initially financed it using our $350 million secured bridge facility and our $450 million unsecured bridge facility while the remainder was financed from our three year revolving facility which was expanded from $900 million to $1.4 billion.

Subsequent to the end of the third quarter, we announced a "bought deal" agreement to sell $400 million of convertible debentures and 3,150,000 trust units at a price of $31.75 per trust unit, net proceeds from which would be used to repay our unsecured bridge facility of $450 million in full and the remainder applied against the $350 million secured bridge 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 disruption in the valuations of all income and royalty trusts. The long term impact of these changes is being evaluated internally as well as through our active participation in the recently created coalition of Canadian energy trusts.

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REVIEW OF QUARTERLY OPERATIONS

Commodity Price Environment	Three months ended Sept. 30			Nine months ended Sept. 30
Benchmarks	2006	2005	Change	2006	2005	Change
West Texas Intermediate crude oil (US$ per barrel)	70.58	63.19	12%	68.25	55.40	23%
Edmonton light crude oil ($ per barrel)	79.07	76.51	3%	75.55	67.91	11%
Bow River blend crude oil ($ per barrel)	58.65	54.94	7%	53.07	44.80	18%
AECO natural gas daily ($ per mcf)	5.64	9.30	(39%)	6.40	7.84	(18%)
AECO natural gas monthly ($ per mcf)	6.03	8.17	(26%)	7.19	7.41	(3%)
Canadian / U.S. dollar exchange rate	0.891	0.833	7%	0.883	0.817	8%

Oil prices have increased in the third quarter of 2006 as compared to the third quarter of 2005. The West Texas Intermediate ("WTI") crude oil price increased by 12%, 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 third quarter of 2006 would have been $79.21 had the dollar not appreciated by 7%. As a result, Edmonton Par only realized a 3% increase over the same period. A similar situation occurred for the nine months ended September 30, 2006 compared to the prior year as WTI increased by 23% while Edmonton Par only increased by 11%. For the nine months ended September 30, 2006, the Canadian dollar equivalent of WTI would have been $77.29, had the Canadian dollar not appreciated by 8%. In addition to the strengthening Canadian dollar, Edmonton Par was impacted by a differential to the WTI in the third quarter. For the nine months ended September 30, 2006, WTI traded at a 2% premium to Edmonton Par versus WTI and Edmonton Par trading evenly in the prior year. The combination of a strengthening Canadian dollar and the widening differential between WTI and Edmonton Par resulted in only an 11% increase in Edmonton Par over the prior year while WTI increased by 23% for the same period.

In the third quarter of 2006, prices for heavy crude oil of $58.65 were 7% higher compared to $54.94 in the same period in 2005. As shown in the table below, Bow River differentials narrowed to 25.8% of Edmonton Par in the third quarter of 2006, compared to 28.2% in the prior year. The heavy crude oil price during the nine months ending September 30, 2006 was 18% higher at $53.07 compared to $44.80 for the same period in 2005. This is due to the narrowing of the Bow River differentials to 29.8% from 34.0%.

		2006			2005			2004
Differential Benchmarks	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Bow River Blend differential to Edmonton Par	25.8%	22.9%	42.0%	40.0%	28.2%	39.6%	37.5%	39.1%

For the three and nine months ended September 30, 2006 compared to the same periods in 2005, AECO natural gas daily prices saw a decrease of 39% and 18%, respectively, while monthly prices for the same periods decreased by 26% and 3% respectively.

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.

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	Three months ended			Nine months ended
	Sept. 30,	Sept. 30,		Sept. 30,	Sept. 30,
	2006	2005	Change	2006	2005	Change
Light to medium oil ($/bbl)	66.64	65.71	1%	62.13	57.05	9%
Heavy oil ($/bbl)	55.09	52.37	5%	48.61	39.98	22%
Natural gas liquids ($/bbl)	61.57	54.23	14%	60.81	46.17	32%
Natural gas ($/mcf)	5.75	10.69	(46%)	6.67	8.31	(20%)
Average realized price ($/boe)	54.92	60.39	(9%)	53.08	49.27	8%
Realized risk management losses ($/boe)(1)	(4.96)	(6.85)	(28%)	(3.86)	(6.76)	(43%)
Net realized price ($/boe)	49.96	53.45	(7%)	49.22	42.51	16%
(1) Includes amounts realized on WTI, heavy price differential and foreign exchange contracts and excludes amounts realized on electricity contracts.

Our average realized prices were 9% lower before losses on risk management contracts and 7% lower after realized losses on risk management contracts for the three months ended September 30, 2006 as compared to the same period in 2005. The WTI price increased by 12% over the same periods, however, this benefit was partially offset by a stronger Canadian dollar resulting in an increase of only 3% for Edmonton Par. This is relatively consistent with the 5% overall increase in our average realized oil price for the three months ended September 30, 2006. 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 28.2% in the third quarter of 2005 compared to 25.8% in the third quarter of 2006. As 37% 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 nine months ended September 30, 2006, the Edmonton Par price increased by 11% and the Bow River price increased by 18%. The net result in the movement of these two benchmarks on our realized price for all of our oil for the nine months ended September 30, 2006 over the same period in the prior year is an increase of 17% before hedging and 25% after oil and currency exchange hedging activities.

For the third quarter of 2006, the realized price of our light to medium oil increased 1% which is relatively consistent with the Edmonton Par increase of 3% for the same period. For the nine months ended September 30, 2006, the realized price of our light to medium oil increased by 9% over the prior year while Edmonton Par increased by 11% over the same period. This increase in our realized light to medium oil price is reasonably in line with the increase in the benchmark prices.

Our realized heavy oil price differential to Edmonton Par for the three months ended September 30, 2006 was 30% compared to 32% for the three months ended September 30, 2005, a 2% improvement. This is expected as the majority of our heavy oil production is priced off of Bow River, which reflected a 2.4% narrowing to Edmonton Par from 28.2% in the third quarter of 2005 to 25.8% in the third quarter of 2006. For the nine months ended September 30, 2006 our realized heavy oil differential to Edmonton Par was 35.7% compared to 41.1% for the prior period. Bow River differentials to Edmonton Par for the nine months ended September 30, 2006 and 2005 were 29.8% and 34.0%, respectively. The narrowing in our realized heavy oil differential by 5.4% is relatively consistent with the 4.2% narrowing for the benchmark.

For the three months ended September 30, 2006, our realized natural gas price decreased by 46% compared to the same period in 2005, while the AECO daily and monthly price decreased by 39% and 26%, respectively. With approximately 85% of our natural gas sales priced off the AECO daily benchmark, 10% priced off AECO Monthly benchmark and the remainder sold to aggregators, our price decreased by more than both indices primarily due to lower production volumes at 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. The lower production in this area had a negative impact on our realized gas price as the properties in this area typically have a higher than average heat content thus typically yielding gas prices in excess of the AECO benchmark prices. For the nine months ended September 30, 2006 our realized natural gas price decreased by 20% relative to the same period in 2005, while the AECO daily and monthly price decrease by 18% and 3% respectively. Our price decreased by more than the decrease in both indices due to the lower production in the Markerville area as noted above.

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Sales Volumes

The average daily sales volumes by product were as follows:

			Three months ended
	Sept. 30, 2006		June 30, 2006		Sept. 30, 2005
							% Volume
							2006 to 2005
							quarterly
	Volume	Weighting	Volume	Weighting	Volume	Weighting	change
Light to medium oil (bbl/d)(1)	28,394	46%	28,951	48%	18,868	50%	50%
Heavy oil (bbl/d)	13,919	22%	13,037	22%	13,735	37%	1%
Total oil (bbl/d)	42,313	68%	41,988	70%	32,603	87%	30%
Natural gas liquids (bbl/d)	2,595	4%	2,016	3%	850	2%	205%
Total liquids (bbl/d)	44,908	72%	44,004	73%	33,453	89%	34%
Natural gas (mcf/d)	103,618	28%	96,848	27%	24,574	11%	322%
Total oil equivalent (boe/d)	62,178	100%	60,145	100%	37,549	100%	66%

	Nine months ended
	Sept. 30, 2006		Sept. 30, 2005
	Volume	Weighting	Volume	Weighting	% Volume Change
Light to medium oil (bbl/d)(1)	27,136	46%	16,618	46%	63%
Heavy oil (bbl/d)	14,003	24%	13,906	39%	1%
Total oil (bbl/d)	41,139	70%	30,524	85%	35%
Natural gas liquids (bbl/d)	2,111	4%	810	2%	161%
Total liquids (bbl/d)	43,250	74%	31,334	87%	38%
Natural gas (mcf/d)	91,379	26%	26,839	13%	240%
Total oil equivalent (boe/d)	58,480	100%	35,807	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 24o (medium grade), however, it benefits from a heavy oil royalty regime and therefore would be classified as heavy oil according to NI 51-101.

In the third quarter of 2006, average production was higher than the same period in 2005 due to the acquisition of Viking in February of 2006 and the Hay River properties during the third quarter of 2005 plus our acquisition of Birchill in the third quarter of 2006. As a result, third quarter 2006 production is more comparable to the second quarter of 2006 than the third quarter of 2005.

Light to medium oil production is down from the second quarter of 2006 due to reduced production in the Hay River area, as the new wells, which were drilled in the first quarter, are coming off their initial production rates as expected, and in the Bellshill area due to power disruptions in the third quarter impacting production. These production decreases were partially offset by production increases attributed to the Birchill acquisition in August 2006.

Heavy oil production for the third quarter of 2006 increased by 7% to 13,919 boe/d compared to 13,037 boe/d for the second quarter of 2006, which is attributable to new wells coming on stream in the Lloydminster and Hayter areas. Heavy oil production for the three and nine months ended September 30, 2006 compared to the same period in 2005 remained relatively consistent as the incremental production added from the Viking assets and our 2006 drilling program was offset by downtime in the Suffield, Hayter and Killarney areas in the second quarter, and coupled with normal production declines.

Natural gas production in the third quarter of 2006 of 103,618 mcf/d is 322% higher compared to production of 24,574 mcf/d for the third quarter of 2005, primarily due to the acquisition of Viking in 2006 and our acquisition in August 2006, which was weighted towards natural gas. Production for the nine months ended September 30, 2006 is 240% or 64,540 mcf/d higher than it was for the nine months ended September 30, 2005. Our third quarter natural gas production was 7% higher than the second quarter of 2006 due to our Birchill acquisition in August 2006 and 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.

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Our production mix reflects the acquisition of the Viking properties and the Hay River acquisition in prior periods. Prior to these acquisitions, we were weighted 39% heavy oil with only 14% natural gas weighting. With these acquisitions and the Birchill acquisition in August 2006, our product mix changed such that approximately 22% of our production is weighted towards heavy oil and 28% towards natural gas. With this change in product mix, we are less exposed to fluctuations in heavy oil differentials and more exposed to natural gas price volatility.

Revenues
		Three months ended
							2006 to
							2005
							Quarter
(000)	Sept. 30, 2006			June 30, 2006	Sept. 30, 2005		Change
Light / medium oil sales	$	174,083	$	172,043	$	114,060	53%
Heavy oil sales		70,541		67,300		66,170	7%
Natural gas sales		54,855		58,045		24,157	127%
Natural gas liquids sales and other		14,701		11,622		4,241	247%
Total sales revenue		314,180		309,010		208,628	51%
Realized risk management contract losses(1)		(28,361)		(24,118)		(23,652)	20%
Net revenues including realized risk management contract losses		285,819		284,892		184,976	55%
Realized electricity price risk management contract gains		4,329		258		1,470	195%
Unrealized risk management contracts (losses) / gains		77,078		(115)		(3,948)	(2,052%)
Net Revenues, before royalties		367,226		285,035		182,498	101%
Royalties		(54,362)		(51,907)		(38,974)	39%
Net Revenues	$	312,864	$	233,128	$	143,524	118%

	Nine months ended
(000)	Sept. 30, 2006		Sept. 30, 2005		Change
Light / medium oil sales	$	460,249	$	258,806	78%
Heavy oil sales		185,828		151,764	22%
Natural gas sales		166,344		60,896	173%
Natural gas liquids sales and other		35,044		10,206	243%
Total sales revenue		847,465		481,672	76%
Realized risk management contract losses(1)		(61,687)		(66,038)	(7%)
Net revenues including realized risk management contract losses		785,778		415,634	89%
Realized electricity price risk management contract gains		5,064		1,783	184%
Unrealized risk management contracts (losses) / gains		35,966		(73,524)	(149%)
Net Revenues, before royalties		826,808		343,893	140%
Royalties		(149,384)		(81,824)	83%
Net Revenues	$	677,424	$	262,069	158%
(1) Includes amounts realized on WTI, heavy price differential and foreign exchange contracts, and excludes amounts realized on electricity contracts.

Our revenue is impacted by production volumes, commodity prices, and currency exchange rates. Light to medium oil sales revenue for the three months ended September 30, 2006 while relatively unchanged from the second quarter of 2006, was $60.0 million (or 53%) higher than in the prior year as a result of a 2% favourable price variance and a 51% favourable volume variance. The favorable volume variances over the prior year are primarily due to the addition of production volumes from the acquisition of Viking and Birchill in 2006 and the Hay River 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.

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Due to our significant property acquisitions since August 2005 (Viking and Hay River) it is more relevant to compare the third quarter of 2006 to the second quarter of 2006. Light to medium oil revenue for the third quarter of 2006 increased by $2.0 million (or 1%) over the prior quarter. This increase is attributed to a $3.5 million favourable price variance and a $1.5 million unfavourable volume variance. The volume variance between the second and third quarter of 2006 is attributed to reduced production in the Hay River area due to new wells drilled in the first quarter coming off their initial production rates as expected and due to power disruptions in the Bellshill area.

For the nine months ended September 30, 2006, our light to medium oil revenue increased by $201.4 million (or 78%). The increase is attributed to a $37.6 million favourable price variance and a $163.8 million favourable volume variance due to the rising Edmonton Par and Bow River prices. Similarly, favourable volume variances are expected due to the Viking and Hay River acquisition and the Birchill acquisition in August 2006.

Heavy oil sales for the three months ended September 30, 2006 increased $4.4 million (or 7%) compared to the same period in the prior year due to a favourable price variance of $3.5 million and a favourable volume variance of $0.9 million. The rising crude oil price environment, including narrowing heavy oil differentials, resulted in higher realized prices on our heavy oil. Heavy oil revenues in the third quarter of 2006 were $3.2 million (or 5%) higher than the prior quarter as a result of an unfavourable price variance of $2.1 million and a favourable volume variance of $5.3 million. The increased in production in the third quarter is the result of downtime in Killarney and Hayter during the second quarter of 2006. For the nine months ended September 30, 2006 our heavy oil revenue increased by $34.1 million (or 22%) over the prior year due to a favourable price variance of $33.0 million and a favourable volume variance of $1.1 million.

Natural gas sales revenue increased by $30.7 million (or 127%) for the three months ended September 30, 2006 over the prior year due to an unfavourable price variance of $47.0 million and a favourable volume variance of $77.7 million. The favourable volume variance is entirely attributed to the incremental gas production from the Viking properties and the Birchill acquisition in August. For the nine months ended September 30, 2006, natural gas sales increased by $105.4 million (or 173%) over the same period in the prior year. The increase is attributed to an unfavourable price variance of $41.0 million and a favourable volume variance of $146.4 million substantially attributed to the Viking acquisition.

For the three and nine months ended September 30, 2006, natural gas liquids revenues increased by $10.5 million (or 247%) and $24.8 million (or 243%), respectively, over the same periods in the prior year with the increase generally due to a higher pricing environment and additional production volumes from the Viking properties.

Risk Management Contracts

Details of our risk management contracts at September 30, 2006, are included in Note 12 of the consolidated financial statements for the three and nine months ended September 30, 2006. The table below provides a summary of net gains and losses on risk management contracts:

	Three months ended
		September 30, 2006									Sept. 30, 2005
(000s)	Oil		Gas		Currency		Electricity		Total		Total
Realized (losses) / gains on risk management contracts	$	(30,006)	$	1,143	$	502	$	4,329	$	(24,032)	$	(22,182)
Unrealized (losses) / gains on risk management contracts		73,405		314		3,688		(361)		77,046		(3,185)
Amortization of deferred charges relating to risk management contracts		-		-		-		-		-		(1,207)
Amortization of deferred gains relating to risk management contracts		-		-		-		32		32		444
Total (losses) / gains on risk management contracts	$	43,399	$	1,457	$	4,190	$	4,000	$	53,046	$	(26,130)

8

	Nine months ended
	September 30, 2006										Sept. 30, 2005
(000s)		Oil		Gas		Currency	Electricity			Total		Total
Realized (losses) / gains on risk management contracts	$	(66,462)	$	3,012	$	1,763	$	5,064	$	(56,623)	$	(64,255)
Unrealized (losses) / gains on risk management contracts		28,947		(293)		9,858		(2,911)		35,601		(65,307)
Amortization of deferred charges relating to risk management contracts		-		-		-		-		-		(9,551)
Amortization of deferred gains relating to risk management contracts		-		-		-		365		365		1,334
Total (losses) / gains on risk management contracts	$	(37,515)	$	2,719	$	11,621	$	2,518	$	(20,657)	$	(137,779)

Our total realized loss on oil and gas price and currency exchange risk management contracts was $28.4 million (or $4.96 per boe) for the three months ended September 30, 2006 compared to $23.7 million (or $6.85 per boe) for the same period in 2005. For the nine months ended September 30, 2006 we recorded a realized loss on oil and gas and currency exchange risk management contracts of $61.7 million (or $3.86 per boe), a decrease of $4.3 million over the realized loss on oil and gas and currency exchange risk management contracts for the nine months ended September 30, 2005 of $66.0 million (or $6.76 per boe).

Our realized loss on oil price contracts for the third quarter of 2006 was $30.0 million compared to $24.0 million in the third quarter of 2005. The increase in our loss is primarily a result of high oil prices in the third quarter of 2006. Our total realized loss on oil contracts includes the impact of the heavy oil differential contracts in place in the third quarter of 2006, with realized losses on these contracts of $3.5 million (or $0.60 per boe) attributed to a narrowing of heavy oil differentials to 25.8% as compared to the contracted differentials of approximately 28-29%. For the three months ended September 30, 2005, we had losses of $2.3 million (or $0.66 per boe) on the heavy oil differential contracts in place when heavy oil differential averaged 28.2%. A slightly lower loss than that realized in the third quarter of 2005 due to the contracted heavy oil differential of 28-29% being approximately the same as that realized in the market. Typically, heavy oil differentials are narrower in the second and third quarter as demand for heavier oil is higher due to paving activity occurring during these times. For the third quarter of 2006, approximately 23,750 bbl/d or approximately 70%, of our net oil production was covered by oil price contracts.

Our total realized loss on oil price risk management contracts for the nine months ended September 30, 2006 was $66.5 million compared to $67.0 million for the same period in 2005. Our realized loss for the nine months ended September 30, 2006 included a $3.6 million (or $0.22 per boe) gain on our heavy oil differential contracts. For the same period in 2005 we incurred a loss of $2.2 million (or $.22 per boe), as these contracts only came into effect at the beginning of the third quarter of 2005 when heavy oil differentials are typically narrow.

We have entered into currency exchange contracts that fix the foreign exchange rate on a portion of our oil revenue. For the three months ended September 30, 2006, we realized gains on our currency exchange contracts of $502,000 or $0.09 per boe ($332,000 or $0.10 per boe for the three months ended September 30, 2005). For the nine months ended September 30, 2006, realized gains on our currency exchange contracts were $1.8 million or $0.11 per boe ($1.0 million or $0.10 per boe for the nine months ended September 30, 2005). During the third quarter we have entered into two foreign exchange contracts for 2007 and one for 2008, details of which are outlined in Note 12 to our third quarter consolidated financial statements. In the third quarter we also entered into shorter term foreign exchange contracts to fix US$750 million of the purchase price we paid for the acquisition of the refinery.

9

For the three and nine months ended September 30, 2006, we realized gains on our gas price risk management contracts of $1.1 million (or $0.20 per boe) and $3.0 million (or $0.19 per boe), respectively. For the third quarter of 2006, approximately 30,000 GJ/d or 29% of our gas production was covered by financial gas price risk management contracts. We did not have any gas price risk management contracts in 2005.

We have also entered into risk management contracts that provide protection from rising power costs. We realized gains on these contracts of $4.3 million (or $0.76 per boe) and $5.1 million (or $0.32 per boe) for the three and nine months ended September 30, 2006, respectively. For the same periods in 2005, our realized gain was $1.5 million (or $0.43 per boe) and a gain of $1.8 million (or $0.18 per boe), respectively. 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 three and nine months ended September 30, 2006, excluding amortization of deferred gains, was $77.0 million (or $13.47 per boe) and $35.6 million (or $2.23 per boe), respectively. For the three and nine months ended September 30, 2005, there was a loss of $3.2 million (or $0.92 per boe) and a loss of $65.3 million (or $6.68 per boe), respectively. Collectively, our risk management contracts had an unrealized mark-to-market deficiency of $18.1 million as at September 30, 2006. The difference between this value and the mark-to-market amount of $52.6 million at December 31, 2005 is included in our unrealized gain in the nine month period ended September 30, 2006. Included within our total unrealized gains on risk management contracts for the three and nine months ended September 30, 2006 is $3.7 million and $9.9 million relating to unrealized gains on our currency exchange risk management contracts. In the third quarter we entered into three additional foreign exchange contracts to fix a portion of our exposure to fluctuations in the foreign exchange rate between the Canadian and the U.S. dollar in 2007 and 2008. In addition, in anticipation of the closing of the refinery acquisition we entered into a series of swaps and forward purchase contracts for US$750 million to be settled in October 2006. In the third quarter of 2006, the total unrealized gain of $3.7 million is comprised of a loss on foreign exchange contracts relating to 2007 and 2008 of $3.3 million and a gain on the contract entered into relating to the refinery purchase of $7.0 million. Refer to Note 12 to the consolidated financial statements for further details of the financial instruments outstanding at September 30, 2006.

Also included in our unrealized risk management contract losses 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 $32,000 and $365,000 of our total unrealized gains on risk management contracts for the three and nine months ended September 30, 2006 and an expense of $444,000 and $1.3 million for the three and nine months ended September 30, 2005. These amounts are discussed further under the heading "Deferred Charges and Credits".

Royalties

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

For the three and nine months ended September 30, 2006, our net royalties as a percentage of gross revenue were 17.3% (18.7% - three months ended September 30, 2005) and aggregated to $54.4 million ($39.0 million – three months ended September 30, 2005). Royalty rates are driven by productivity and price. The decrease in the royalty rate is attributable to lower royalty rates in the Hazelwood and Hayter area in the third quarter of 2006 relative to the same period in 2005, as new wells in these areas in the third quarter of 2005 were incurring royalty rates at the upper end of the royalty scale. For the nine months ended September 30, 2006, our net royalties as a percentage of gross revenue were 17.6% (17.0% - nine months ended September 30, 2005) and aggregated to $149.4 million ($81.8 million – nine months ended September 30, 2006). An 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 (realized 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 affect the first quarter of 2006 but not the first quarter in the prior year.

10

Operating Expense
	Three months ended						Nine months ended
($000s)	Sept. 30, 2006		June 30, 2006		Sept. 30. 2005		Sept. 30, 2006		Sept. 30, 2005
Operating expense
Power	$	17,491	$	12,227	$	9,617	$	41,746	$	25,263
Workovers		13,203		12,843		6,543		35,392		22,405
Repairs and maintenance		5,762		7,317		3,158		17,707		8,445
Labour – internal		5,260		5,912		1,542		15,105		5,766
Processing fees		4,991		4,774		766		14,094		3,960
Fuel		1,710		2,382		1,382		6,121		3,722
Labour – external		3,239		3,541		1,105		9,775		4,604
Land leases and property tax		6,193		4,355		2,994		15,119		5,973
Other		4,640		7,242		5,278		18,117		7,984
Total operating expense		62,489		60,593		32,385		173,176		88,122
Realized gains on power risk management contracts		(4,329)		(258)		(1,470)		(5,064)		(1,783)
Net operating expense	$	58,160	$	60,335	$	30,915	$	168,112	$	86,339
Transportation and marketing expense	$	3,535	$	4,065	$	56	$	9,223	$	302
Net operating Expense ($/boe)	$	10.17		$11.02	$	8.95	$	10.53	$	8.83
Transportation and marketing expense ($/boe)	$	0.62	$	0.74	$	0.02	$	0.58	$	0.03

Total operating expense increased by $30.1 million (or 93%) and $85.1 million (or 97%) respectively for the three and nine months ended September 30, 2006 compared to the same periods in the prior year. For the three months ended September 30, 2006, approximately $25.7 million of the increase ($50.1 million for the nine months ended September 30, 2006) is due to increased activity associated with the Viking properties acquired in February 2006. The remainder of the increase is attributed to increased power costs, and the continued high demand for oilfield services leading to higher costs for well servicing, workovers and well maintenance. The increases in total operating expenses for the nine months ended September 30, 2006 compared to the same period in the prior year are attributed to incremental operating costs attributed to the Viking, Hay River and the Birchill acquisition, costs associated with incremental drilling activities and generally higher costs in the industry.

Our operating expenses will benefit from our capital spending program, a portion of which is directed towards operating cost reduction initiatives such as the water disposal and fluid handling project in Suffield where we incurred approximately $10 million in capital expenditures to enable us to operate high water cut wells more economically. These projects, combined with the acquisition of Birchill in August 2006, which has lower operating costs per boe will assist in offsetting the cost pressures in the oil and gas services industry.

Our transportation costs of $2.9 million ($56,000 – three months ended September 30, 2005) and $7.4 million ($302,000 – nine months ended September 30, 2005) for the three and nine months ended September 30, 2006, respectively, 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. Marketing costs relate to those amounts charged for our marketing function which is outsourced.

The addition of the Viking properties and the Hay River properties to our portfolio significantly impacts comparability between the third quarter of 2006 and the third quarter of 2005. For a better comparison, our third quarter of 2006 operating expenses increased by $1.9 million compared to the second quarter of 2006. The most significant portion of the increase (approximately $1.3 million) is attributable to having two months of operating expenses related to the properties acquired in the Birchill acquisition which occurred in the third quarter of 2006, which was partially offset by lower repairs and maintenance activity as most of the servicing costs were incurred in the second quarter.

11

Electricity costs represent a significant portion of our total operating costs (approximately 28% in the third quarter of 2006 and 24% year to date). In the third quarter of 2006, electricity costs per megawatt hour ("MWh") were 42% higher than they were in the third quarter of 2005. These increases were offset by the Viking properties which have lower power usage per boe of production, and the Hay River properties which operate using internally generated 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 power cost despite rising prices. For the nine months ended September 30, 2006, we are seeing similar results. With a 25% increase in the per MWh cost of power we experienced only a 1% increase in our per boe power costs which is attributed to the same factors noted above. The following table details the power costs per boe before and after the impact of our hedging program.

	Three months ended								Nine months ended
							2006 to
							2005
	Sept. 30,		June 30,		Sept. 30,		Quarter	Sept. 30,		Sept. 30,
($ per boe)		2006		2006		2005	Change		2006		2005	Change
Power costs	$	3.06	$	2.23	$	2.78	10%	$	2.61	$	2.58	1%
Realized gains on electricity risk management contracts		(0.76)		(0.05)		(0.43)	77%		(0.32)		(0.18)	78%
Net power costs	$	2.30	$	2.18	$	2.35	(2%)	$ 2.29		$	2.40	(5%)
Alberta Power Pool electricity price ($ per MWh)	$	94.74	$	53.59	$	66.79	42%	$	68.36		$54.72	25%

Approximately 65% of our estimated Alberta electricity usage is 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 in 2006 and future periods that are dedicated to increasing our power efficiency.

Operating Netback

	Three months ended				Nine months ended
($ per boe)	Sept. 30, 2006		Sept. 30, 2005		Sept. 30, 2006		Sept. 30, 2005
Revenues	$	54.92	$	60.39	$	53.08	$	49.27
Realized loss on risk management contracts(1)		(4.96)		(6.85)		(3.86)		(6.76)
Royalties		(9.50)		(11.28)		(9.36)		(8.37)
As a percent of revenue		17.30%		18.68%		17.63%		16.99%
Operating expense(2)		(10.17)		(8.96)		(10.53)		(8.87)
Transportation expense		(0.62)		(0.02)		(0.58)		(0.03)
Operating netback(3)	$	29.67	$	33.28	$	28.75	$	25.24
(1) Includes amounts realized on WTI, heavy price differential and foreign exchange contracts, and excludes amounts realized on electricity contracts.
(2) Includes realized gain on electricity risk management contracts of $0.76 per boe and $0.43 per boe for the three months ended September 30, 2006 and 2005 and $0.32 and $0.18 for the nine months ended September 30, 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 $3.61 per boe lower and $3.51 per boe higher for the three and nine months ended September 30, 2006, respectively, than for the same periods of 2005. Lower natural gas prices in 2006 more than offset gains in oil prices resulting in a lower realized price per boe by $5.47/boe ($3.81/boe increase for the nine month period), which were partially offset by lower losses realized on our price risk management program of $1.89/boe ($2.90/boe for the nine month period). For the third quarter of 2006 we realized lower royalties by $1.78/boe ($0.99/boe higher for the nine month period) and higher operating costs (including transportation) of $1.81/boe ($2.21/boe for the nine month period).

12

General and Administrative (G&A) Expense
	Three months ended								Nine months ended
							2006 to 2005
		Sept. 30,	June 30,			Sept. 30,	Quarter	Sept. 30,			Sept. 30,
($000s except per boe)		2006		2006		2005	Change		2006		2005	Change
Cash G&A(1)	$	6,962	$	7,756	$	3,773	85%	$	20,771	$	9,970	108%
Unit based compensation expense		538		757		9,198	(94%)		1,054		15,076	(93%)
Total G&A	$	7,500	$	8,513	$	12,971	(42%)	$	21,825	$	25,046	(13%)
Cash G&A per boe ($/boe)		1.22		1.42		1.09	12%		1.30		1.02	27%
Transaction costs
Unit based compensation expense		-		330		-	-		8,974		-	100%
Severance and other		-		-		-	-		3,098		-	100%
Total Transaction costs	$	-	$	330	$	-	-	$	12,072	$	-	100%
(1) Cash G&A excludes the impact of our unit based compensation expense and other one time transaction costs.

For the three months ended September 30, 2006, Cash G&A costs increased by $3.2 million (or 85%) compared to the same period in 2005. For the nine months ended September 30, 2006, Cash G&A increased by $10.8 million (or 108%). The increase is attributed mainly to increased staffing levels due to the Viking acquisition. Approximately $4.4 million (or 63%) of our third quarter 2006 Cash G&A and $13.5 million (or 65%) of our nine months ended September 30, 2006 Cash G&A expenses are related to salaries and other employee related costs while in the third quarter of 2005 only $1.8 million (or 48%) of our Cash G&A and $5.3 million (or 53%) of our nine months ended September 30, 2005 was made up of these costs. The acquisition of Viking in February 2006 doubled our overall staffing levels, adding approximately 100 additional employees. The remainder of the increases in the three and nine months ended September 30, 2006 compared to the same periods in 2005 are due to the work undertaken for compliance with the Sarbanes Oxley Act and generally higher costs in the industry. In particular, for the nine months ended September 30, 2006, our Cash G&A costs include $826,000 of bonus payments relating to 2005 and $560,000 of costs incurred for third party consultants incurred 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 based on the difference between the trust unit trading price and the strike price of the unit appreciation rights ("UAR") adjusted for the proportion that is vested. Our total unit based compensation expense for the three months ended September 30, 2006 was $0.5 million, consisting of $1.3 million of cash compensation, $1.4 million of unit settled compensation and a $2.2 million non-cash recovery. Our total unit based compensation expense for the nine months ended September 30, 2006, including $9.0 million allocated to transaction costs, was $10.0 million, consisting of $8.3 million of cash compensation, $8.8 million of unit settled compensation and a $7.1 million non-cash recovery. 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 $33.21 at June 30, 2006, and at September 30, 2006 our trust unit price had decreased to $30.25. As a result, we have recorded a recovery on unexercised UARs at September 30, 2006. Our total unit based compensation expense, including that portion which has been allocated to transaction costs, decreased by $8.7 million for the three month period ended September 30, 2006 and decreased by $5.0 million for the nine month period ended September 30, 2006 over the same period in 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. As a result, we have reflected $9.0 million, related to the additional expense incurred as a result of the accelerated vesting of our units, as a transaction cost. The remaining $3.1 million recorded as transaction costs are related to severance payments made to Harvest employees upon merging with Viking.

13

Interest Expense
	Three months ended								Nine months ended
($000s except per boe)							2006 to
							2005
	Sept. 30,		June 30,		Sept. 30,		Quarter	Sept. 30,		Sept. 30,
		2006		2006		2005	Change		2006	2005	Change
Interest on short term debt	$	-	$	-	$	1,083	(100%)	$	-	$ 3,953	(100%)
Amortization on deferred charges – short term debt		-		-		-	-		-	2,499	(100%)
Total interest on short term debt		-		-		1,083	(100%)		-	6,452	(100%)
Interest on long-term debt
Senior notes		5,488		5,573		6,050	(9%)		16,785	18,236	(8%)
Convertible debentures		4,674		4,623		924	406%		12,593	1,730	628%
Bank loan		5,797		3,013		-	100%		10,263	-	100%
Amortization of deferred charges – long term debt		726		772		708	3%		2,932	1,494	96%
Total interest on long term debt		16,685		13,981		7,682	117%		42,573	21,460	98%
Total interest expense	$	16,685	$	13,981	$	8,765	90%	$	42,573	$ 27,912	53%

Interest expense for the three and nine months ended September 30, 2006 was higher by $7.9 million and $14.7 million, respectively than for the same period in the prior year primarily due to additional convertible debentures outstanding in the second half of 2005, and convertible debentures assumed with our acquisition of Viking. Compared to the second quarter of 2006, the current quarter interest expense is $2.7 million higher due to an increase in the bank loan as a result of the acquisition of Birchill.

Interest expense includes the charges on outstanding bank debt, convertible debentures and senior notes as well as the amortization of related financing costs. After entering into a new credit facility on February 3, 2006, interest on our bank debt is determined using a floating rate based on banker's acceptances plus 65 to 115 basis points based on our Senior Debt to Cash Flow ratio. Our interest expense on bank loans has increased by approximately $4.7 million and $6.3 million respectively for the three and nine months ended September 30, 2006 as compared to the same period in 2005, due to our merger with Viking, when we assumed approximately $106.2 million and the acquisition of Birchill which resulted in additional bank debt of approximately $232.6 million.

Subsequent to September 30, 2006 we expanded our three year revolving credit facility to $1.4 billion, and arranged for a $350 million secured bridge facility and a $450 million unsecured bridge facility. The additional financing was completed in connection with the purchase of the shares of North Atlantic Refinery Limited. Further details on the expanded credit facility and the bridge financing are included under "Liquidity and Capital Resources".

At September 30, 2006, we had five series of convertible debentures outstanding, including a 10.5% and 6.40% series, which were assumed in conjunction with the Viking acquisition. Details of the terms of each convertible debenture are outlined in Note 8 of the consolidated financial statements for the three months and nine months ended September 30, 2006. Interest on the convertible debentures is reported based on the effective yield of the debt component of the convertible debentures. Interest expense on convertible debentures for the three months and nine months ended September 30, 2006, is $3.8 million and $10.9 million higher respectively, compared to the same period in 2005, as it includes interest expense on approximately $202.5 million of additional convertible debentures that have been assumed with the merger with Viking on February 3, 2006, as well as a full period of interest expense 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. Though holders of the 9%, 8%, 6.5% and 10.5% convertible debenture series have continued to convert many of their convertible debentures to Harvest 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. In future quarters, interest expense on convertible debentures, not considering future conversions, should remain relatively consistent with the interest expense in the third quarter of 2006, as a full three months of interest expense on the convertible debentures assumed in the Viking's acquisition has been incurred in the quarter. During the quarter, $5.4 million of convertible debentures were converted into 193,186 trust units ($12.5 million convertible debentures converted to 466,466 trust units for the nine months ended September 30, 2006).

14

Our U.S. dollar denominated senior notes, which bear interest at 7 7/8%, mature on October 15, 2011 and have an early redemption feature, provide an offset to fluctuations in currency exchange rates. Interest expense for the three and nine months ended September 30, 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 total 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 costs incurred to secure credit facilities, all totaling $1.1 million and $4.0 million for the three and nine months ended September 30, 2006, respectively ($0.9 million and $4.3 million for the three and nine months ended September 30, 2005).

Depletion, Depreciation and Accretion Expense
	Three months ended							Nine months ended
	Sept. 30,		June 30,		Sept. 30,			Sept. 30,		Sept. 30,
(000s except per boe)		2006		2006		2005	Change		2006		2005	Change
Depletion and depreciation	$	106,922	$	88,886	$	40,356	165%	$	273,203	$	109,320	150%
Depletion of capitalized asset retirement costs		4,219		4,230		6,228	(32%)		12,731		11,597	10%
Accretion on asset retirement obligation		4,082		4,062		2,385	71%		11,792		7,026	68%
Total depletion, depreciation and accretion	$	115,223	$	97,178	$	48,969	135%	$	297,726	$	127,943	133%
Per boe ($/boe)		20.14		17.76		14.18	42%		18.65		13.09	42%

Our overall depletion, depreciation and accretion (DD&A) expense for the three and nine months ended September 30, 2006 is $66.3 million and $169.8 million higher compared to the same period in 2005. An increase of $32.1 million of the increase for the three months ended September 30, 2006 ($81.0 million for the nine months ended September 30, 2006) is due to the incremental production from the acquisitions made in the latter half of 2005 and the merger with Viking in the first quarter of 2006 and $34.2 million of the increase for the three months ended September 30, 2006 ($88.8 million for the nine months ended September 30, 2006) is due to a higher depletion rate also reflecting the Hay River and Viking acquisitions. These acquisitions have increased our overall corporate DD&A rate due to their higher cost as compared to prior property acquisitions.

Foreign Exchange Gain

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 senior notes, as well as any other U.S. dollar deposits and cash balances. At September 30, 2006, the Canadian dollar strengthened against the U.S. dollar compared to December 31, 2005, and we incurred an unrealized gain on our senior notes of $11.3 million, as well as realized gains on other U.S. denominated transactions of $1.0 million, which was partially offset by unrealized losses on U.S. dollar deposits of $1.0 million for a total currency exchange gain of $11.3 million reported in the first nine month of 2006.

Deferred Charges and Credits

The deferred charges balance on the balance sheet is comprised of four main components: deferred financing charges, discount on senior notes, premium on our office lease 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. The following table provides a summary of the components of the deferred charges at September 30, 2006 as compared to 2005.

15

							Discontinuation
	Financing		Discount on				of Hedge
(000s)		Costs	Senior Notes		Office Leases			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		1,183		-		931		-		2,114
Transferred to Unit issue costs on conversion of debentures		(169)		-		-		-		(169)
Amortization		(2,925)		(222)		(149)		-		(3,296)
Balance, September 30, 2006	$	9,153	$	1,482	$	782	$	-	$	11,417

In the first quarter of 2006, $0.9 million of deferred charges were added to our balance sheet with respect to an office lease assumed through our acquisition of Viking which had a contracted rate per square foot less than current market rates. This lease extends until February 2010 and the related deferred charge will be amortized over the remaining lease period. Additions to deferred financing costs in the first quarter of 2006 relate to the execution of our new credit agreement on February 3, 2006.

At September 30, 2006 our deferred credit balance was $0.9 million of which $32,000 related to the discontinuation of hedge accounting principles ($398,000 at December 31, 2005). This amount will be fully amortized by the end of 2006. The remaining deferred credit balance on the consolidated balance sheet includes a leasehold improvement credit of $832,000, relating to the leasehold improvement costs reimbursed by the landlord. The credit is amortized over the lease term as a reduction of rent expense.

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 September 30, 2006, we have recorded $656.2 million of goodwill on our balance sheet, 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.

Future Income Tax

For the three and nine months ended September 30, 2006, we have not recorded a future income tax balance on our balance sheet as our total deductible temporary differences exceeded our taxable temporary differences such that an asset was created. As we do not expect we will be able to recover the asset, we have not recorded it on our balance sheet. For the three and nine months ended September 30, 2006 we recorded a future income tax recovery of nil and $2.3 million respectively ($1.2 million expense and $28.6 million recovery for the three and nine months ended September 30, 2005). The significant recovery in the nine months ended September 30, 2005 related to losses recorded in the corporate subsidiaries of the Trust.

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.

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Our asset retirement obligation increased by $82.5 million in the nine months ended September 30, 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 first nine months of the year, an increased estimate of existing liabilities, and accretion expense, offset by actual asset retirement expenditures made in the period.

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 three months ended September 30, 2006 was nil ($219,000 for the three months ended September 30, 2005) versus a gain of $65,000 for the nine months ended September 30, 2006 ($156,000 gain for the nine months ended September 30, 2005).

Liquidity and Capital Resources

At the end of the Third Quarter of 2006, our bank borrowings totaled $591.2 million, an increase of $363.6 million during the quarter. The principal components of the increase in bank borrowings were the partial funding of our acquisition of Birchill accounting for $232.4 million plus the US$100 million (CDN$111.3 million) performance deposit required for our agreement to purchase a 115,000 barrel per stream day crude oil refinery and related marketing business with the residual used to fund capital expenditures.

During the three months ended September 30, 2006, our Cash Flows totaled $147.5 million, excluding $516,000 of one time cash transition costs, consistent with $147.0 million, after excluding $670,000 of one time cash transition costs, in the second quarter of 2006. Distributions, net of participation in our reinvestment plans, totaled $73.6 million while our capital expenditures totaled $129.1 million resulting in a $55.2 million deficiency which has been partially funded by bank borrowings. Our working capital deficiency of $48.4 million at the end of the third quarter 2006 as compared to a deficiency of $6.6 million at the end of June 2006 also reflects the impact of this higher level of capital spending. During the first nine months of 2006, Cash Flow totaled $395.5 million with cash distributions paid to unitholders totaling $184.7 million resulting in $210.8 million remaining to fund capital expenditures of $286.5 million. This compares with $213.4 million of Cash Flow, cash distributions paid of $74.3 million, capital expenditures of $81.0 million and debt repayments of $40.9 million for the comparable period in the prior year.

Distributions declared for the nine months ended September 30, 2006 totaled $333.8 million representing 83% of Cash Flow after excluding $6.3 million of one time cash transaction costs. Of the total distributions declared, $133.8 million have been settled with trust units as a result of unitholders choosing to participate in our distribution reinvestment plans which represents a participation rate of approximately 40%, as adjusted for the one month delay between declaration and payment of distributions. On October 4, 2006, we announced the declaration of a $0.38 per trust unit distribution for each of October, November and December based on forecasted commodity price levels and operating performance that are consistent with the current environment.

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On July 26, 2006, we announced a definitive agreement to acquire Birchill for cash consideration of $451.0 million which was ultimately funded through $218.6 million of net proceeds from the issuance of 7,026,500 trust units at a price of $32.75 per trust unit and $232.4 million of bank borrowings. The operations of this acquisition have been included in Harvest consolidated results commencing July 26, 2006, the date of signing of the definitive agreement.

At the end of September 30, 2006, our Senior Debt to Cash Flow ratio was 1.1 to1.0, the Total Debt (excluding convertible debentures) was 1.7 to 1.0 while the Senior Debt to Total Capitalization was 17% and Total Debt to Total Capitalization was 24%, all within the financial covenants of our credit facilities of less than 3.0, 3.5, 50% and 55%, respectively.

On August 22, 2006, concurrent with our announcement to acquire North Atlantic Refining and related businesses for approximately US$1.4 billion, we announced an increase in our facilities from $900 million to $2.2 billion contingent on the closing of this acquisition. The $2.2 billion credit facility is comprised of a $1.4 billion Three Year Revolving Credit Facility, a $350 million Senior Secured Bridge Facility and a $450 million Senior Unsecured Bridge Facility. The $350 million Senior Secured Bridge Facility requires repayment in full with in 18 months while the $450 million Senior Unsecured Bridge Facility requires repayment in full in 6 months. During the month of September, this $2.2 billion underwritten credit facility was successfully syndicated to include Canada's six chartered banks and seven other well respected global financial institutions. An amended and restated credit agreements supports the increased $1.4 billion Three Year Revolving Credit Facility as well as establishes the $350 million Senior Secured Bridge Facility and maintains the financial covenants and pricing of the previous $900 million facility plus adds a 15 basis point administration fee for the period that the $450 million Senior Unsecured Bridge Facility is outstanding. The $350 million Senior Secured Bridge Facility and the $450 million Senior Unsecured Bridge Facility each require that net proceeds from an issuance of equity, equity-like securities (including convertible debentures) and term debt be applied to reduce these credit facilities.

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 Refining acquisition. As events unfolded, we rolled this commitment forward to October 19, 2006, the ultimate closing date. Our planned financing for this US$1.4 billion was to fund approximately $800 million from the issuance of equity and equity-like securities, typically raised in Canadian dollars, and the balance in US dollar denominated debt, initially with US dollar bank borrowings and subsequently with longer tenure fixed interest rate US dollar debt. The forward purchase enabled us to fix the currency exchange risk on the anticipated portion of the US$1.4 billion commitment to be funded from the Canadian dollar sources while anticipating that the balance would be financing in US denominated debt for the long term.

On October 19, 2006, we closed the acquisition of the refinery with the payment of approximately US$1,405 million including the release of the US$100 million deposit to the vendor. The additional US$1,305 million was funded from our credit facilities with US$554.7 million borrowed in US dollars bearing interest at the London Inter Bank Offer Rate ("LIBOR") plus 75 basis points, CDN$450 million borrowed under the Senior Unsecured Bridge Facility bearing interest at bankers acceptances plus 240 basis points, CDN$350 million borrowed under the Senior Secured Bridge Facility and CDN$428.5 million under the Three Year Revolving Facility both bearing interest at bankers acceptances plus 75 basis points.

Concurrent with the closing, North Atlantic Refining entered into a Supply and Offtake Agreement with the vendor of North Atlantic Refining which provided that the ownership of substantially all crude oil feedstock and refined product inventory at the refinery be retained by the counterparty to the agreement. The Supply and Offtake Agreement provides North Atlantic Refining with a continuous supply of crude oil feedstock and a commitment to purchase substantially all of the refined product it produces at market prices subject to a US$0.08 per barrel charge on the crude oil supplied and a time value of money fee to reflect the cost of financing the ownership of the crude oil feedstock and the refined product inventory. The cost of financing reflects a charge equivalent to LIBOR plus 350 basis points. This entire agreement may be terminated by either party at the end of an initial two year term and at any time thereafter, by providing notice of termination no later than six months prior to the desired termination date or if the refinery is sold in an arms length transaction, on 30 days notice. Should the Supply and Offtake Agreement be terminated, North Atlantic Refining would be required to purchase the crude oil feedstock committed to the refinery at that time.

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On October 25, 2006, we entered into an agreement with a syndicate of underwriters to sell, on a "bought deal" basis, a combination of $400 million principal amount of 6.30% convertible unsecured subordinated debentures (the "Debentures") and 3,150,000 trust units at a price of $31.75 per trust unit to raise gross proceeds of approximately $500 million. We also granted the underwriters an over-allotment option to purchase up to an additional 15% of the Debentures and an additional 15% of trust units at the same offering prices for a period of 30 days following closing of this financing. Pursuant to the requirements of our agreement with the underwriters, we have filed the preliminary prospectus on October 31, 2006. The underwriting agreement includes a provision that entitles each underwriter to terminate and cancel their respective obligations if, among other things, prior to closing, there is announced any changes or proposed change to the income tax laws of Canada or their interpretation or administration which would, in the underwriter's opinion, be expected to have a significant adverse effect on the market price or value of the Debenture and/or trust units.

On October 31, 2006, Canada's Finance Minister announced a proposal to amend the Income Tax Act (Canada) to apply a tax on distributions from certain publicly-traded trusts, including Harvest. Under the proposal, certain existing trusts will be subject to the new tax measures commencing in 2011 following a four year grace period. In simplified terms, under the proposed tax amendment, income distributions from certain trusts will first be taxed at the trust level an estimated rate of 31.5%. Such income distributions to unitholders will then be treated as dividends from a taxable Canadian corporation and eligible for the applicable dividend tax credits. The net impact on taxable Canadian unitholders is expected to be minimal. However, as a result of the 31.5% tax at the trust level, distributions to tax exempt unitholders and non-residents of Canada will be subject to tax.

As of November 8, 2006, we are in discussions with our underwriters and are assessing various alternatives to proceed with our planned issuance of convertible debentures and trust units.

Subsequent to closing our acquisition of North Atlantic Refining, our bank borrowing totaled approximately $2,088 million with $112 million of additional borrowing available under the $1.4 billion Three Year Revolving Credit Facility.

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	$	870,614	$	-	$	-	$	591,189	$	279,425
Interest on long-term debt(4)		186,290		13,052		104,418		51,457		17,363
Interest on convertible debentures(3)		84,213		4,364		31,775		27,548		20,526
Operating and premise leases		13,663		1,508		7,076		5,079		-
Capital commitments(5)		17,041		5,556		11,485		-		-
Asset retirement obligations(6)		635,910		2,226		10,959		15,359		607,366
Total	$	1,807,731	$	26,706	$	165,713	$	690,632	$	924,680
(1)    As at September 30, 2006, we had entered into physical and financial contracts for production with average deliveries of approximately 23,750 barrels of oil equivalent per day in the balance of 2006, 27,500 barrels of oil equivalent per day in 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 12 to the consolidated financial statements for further details.

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(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

Off Balance Sheet Arrangements

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

Capital Expenditures

	Three months ended					Nine months ended
	Sept. 30,		Sept. 30,			Sept. 30,		Sept. 30,
(000s)		2006		2005	Change		2006		2005	Change
Development capital expenditures excluding acquisitions and non-cash items	$	129,054	$	31,655	308%	$	286,523	$	81,032	254%
Non-cash capital additions (recoveries)		(236)		1,939	(112%)		(409)		2,974	(114%)
Total development capital expenditures		128,818		33,593	283%		286,114		84,006	241%
Net property acquisitions		312		(839)	(137%)		23,984		2,791	759%
Net business acquisitions		563,561		210,505	168%		563,561		236,505	138%
Total net capital asset expenditures	$	692,691	$	243,259	185%	$	873,659	$	323,302	170%

In the third quarter of 2006 we invested $129.1 million into our portfolio of drilling, optimization and enhancement activities compared to $31.7 million in the third quarter of 2005. Approximately 64% of our third quarter expenditures were spent on drilling 76 gross (60 net) wells with a success rate of 97%. A significant portion of our drilling activity focused on oil opportunities as we expect the current strong oil pricing environment to continue. Our most active drilling area was southeast Saskatchewan where we drilled 17 gross (17 net) horizontal wells during the quarter, bringing our total for the year to 28 gross (28 net) wells. At Lloydminster, a successful horizontal well test in 2005 was followed up with the drilling of 9 gross (9 net) horizontal wells to date in 2006, 6 gross (6 net) in the third quarter. At Hayter and Suffield we continue to find incremental oil from the Dina and Glauconitic formations with a total of 9 and 7 gross (8.5 and 7.0 net) infill horizontal wells drilled in the quarter in these two areas. Water handling upgrades at Suffield were also completed during the quarter, which will allow us to optimize production of both existing and newly drilled wells throughout the fourth quarter.

In the first nine months of 2006 we drilled 195 gross wells, with an additional 40 to 50 gross wells planned for the balance of the year. With the acquisition of Birchill in August 2006, we increased our 2006 capital budget by $50 million to $300 million, including $25 million budgeted specifically for the newly acquired properties.

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The following summarizes our participation in gross and net wells drilled during the third quarter of 2006:

	Total Wells		Successful Wells		Abandoned Wells
Area	Gross	Net	Gross	Net	Gross	Net
South East Saskatchewan	17	17	17	17	-	-
Hayter	9	8.5	9	8.5	-	-
Suffield	7	7	7	7	-	-
Markerville	6	2.8	6	2.8	-	-
Lloydminster	6	6	6	6	-	-
Red Earth	2	1.6	2	1.6	-	-
Wainwright	-	-	-	-	-	-
Other Areas(1)	29	17.1	27	15.4	2	1.7
Total	76	60	74	58.3	2	1.7
(1) Other areas include locations such as Ferrier, Bashaw, Wilsden Green, Alexis, Parkland, Badger, and Pembina

The following summarizes our participation in gross and net wells drilled for the nine months ended 2006:

	Total Wells		Successful Wells		Abandoned Wells
Area	Gross1	Net	Gross	Net	Gross	Net
South East Saskatchewan	28	28	28	28	-	-
Hay River	27	26.4	27	26.4	-	-
Markerville	17	7.7	17	7.7	-	-
Wainwright	14	14	14	14	-	-
Hayter	12	11.4	12	11.4	-	-
Suffield	13	13	13	13	-	-
Red Earth	12	10.5	12	10.5	-	-
Lloyd	9	9	9	9	-	-
Other Areas	63	32.7	59	30	4	2.7
Total	195	152.7	191	150	4	2.7
(1) Excludes 14 additional wells that we have an overriding royalty interest in.

Distributions to Unitholders and Taxability

In the third quarter of 2006, we declared distributions of $1.14 per trust unit ($123.1 million) to Unitholders. This represents a 20% increase in distributions declared over the $0.95 per trust unit declared in the third quarter of 2005. The aggregate of distributions declared during the third quarter of $123.1 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 approximately 58 million following the acquisition of Viking and the Hay River property and continued DRIP participation.

	Three months ended						Nine months ended
		Sept. 30,	Sept. 30,				Sept. 30,		Sept. 30,
(000s except per trust unit amounts)		2006		2005	Change		2006		2005	Change
Distributions declared	$	123,112	$	46,691	164%	$	333,813	$	108,957	206%
Per trust unit	$	1.14	$	0.95	20%	$	3.39	$	2.15	58%
Taxability of distributions (%)		100%		100%	-		100%		100%	-
Per trust unit	$	1.14	$	0.95	20%	$	3.39	$	2.15	58%
Payout ratio (%)(1)		83%		45%	38%		84%		46%	38%
(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.

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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

At the end of the Third Quarter of 2006, our exit rate of production was approximately 65,000 boe/day which represents our productive capacity going into the fourth quarter of 2006. Currently, we are managing some disruptions in transportation of crude oil out of northeastern British Columbia as a third party pipeline system experiences temporary operating shutdowns and this will increase our transportation charges in the fourth quarter and will impact on our Hay River production. We anticipate that the fourth quarter production will bring our average daily production for the year to 60,000 boe/d reflecting the inclusion of the Viking Energy Royalty Trust production effective on February 3, 2006 and the acquisition of Birchill effective July 26, 2006.

Our operating costs for the fourth quarter are expected to be approximately $10.20 per boe reflecting the $4.00 per boe average operating cost of Birchill. Further, our fourth quarter unit operating costs will benefit from a higher level of continuous production partially offsetting the cost pressures driven by the record activity levels in Alberta's oil field service industry.

We expect the WTI benchmark price of crude oil to average approximately US$60 for the fourth quarter with the heavy oil differential to be approximately 35% while the price of AECO gas to average $6.00. With these expectations, we anticipate that our crude oil price risk management contracts with floor price protection of approximately US$45 on 23,750 bbl/day during the fourth quarter to result in approximately $20 million of foregone revenues during the quarter while our natural gas collars will have no impact as our price expectations are within the collared prices.

With third quarter capital spending of $129.1 million bringing our year-to-date spending to $286.5 million, we are now forecasting that capital spending for 2006 will net approximately $325 million including the acceleration of some 2007 budgeted opportunities due to favourable weather conditions in Western Canada and equipment availability.

At the closing, the North Atlantic Refining operations were in a planned maintenance turnaround on several significant processing units. This turnaround is expected to be completed in early November. Subsequent to closing on the acquisition October 19, 2006, we anticipate that the refinery will produce 7.5 million barrels of refined products during the fourth quarter and that the refining margins will range between US$5 and US$7 while operating costs should aggregate to approximately $30 million resulting in an operating contribution of approximately $20 million which should more than offset the capital expenditures and turnaround costs incurred during the period.

We have announced a monthly distribution of $0.38 per trust unit for October, November and December based on our expectation of continued commodity price strength. Our payout ratio is expected to be approximately 85% for 2006 based on an aggregate distribution of $4.53 per trust unit. Currently, our distribution reinvestment plans enjoy a level of participation in excess of 40% and we will use this source of funding to round out the financing of our 2006 capital expenditure program.

On October 19, 2006, we completed our US$1.4 billion acquisition of North Atlantic Refining and funded 100% of the closing with proceeds from our recently increased credit facilities including a 6 month and 18 month bridge facility in the amount of $450 million and $350 million, respectively. On October 26, 2006, we entered in to a $500 million "bought deal" financing the proceeds of which were intended to repay the full amount of the 6 month bridge facility and repay some portion of the 18 month bridge. On October 31, 2006, Canada's Minister of Finance announced a proposal to amend the Income Tax Act (Canada) to impose a 31.5% distributions tax on certain publicly-traded trust, including Harvest. This announcement may enable the underwriters' to terminate their obligation to Harvest. As of the date of this MD&A, we remain in discussions with our underwriters and are assessing various alternatives to proceed with our planned issuance of convertible debentures and trust units. A more detailed description of this situation is provided in the Liquidity and Capital Resources section of this MD&A.

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We continue to be actively evaluating our portfolio of oil and natural gas properties with an intent to dispose of properties where, in our view, their full value can be realized with the disposition proceeds. We currently have such minor dispositions in progress with aggregate proceeds of approximately $20 million expected. We also are active acquisitors of small properties that are complementary to our core properties provided the economics are supportive. Our annual expectation is that the volumetric gain (or reduction) from this activity will be modest and cash flow neutral. It is unlikely that we will be an active participant in the bidding for large scale properties in western Canada which has become very competitive with a modest supply of attractive opportunities. We anticipate that one of the outcomes of the Government's proposal to implement a 31.5% distribution tax will be to accelerate the rationalization/consolidation of the energy trust sector in western Canada and we expect to be an active participant for the appropriate opportunity.

For 2007, we are expecting upstream production volume to average 65,000 boe/d with unit operating costs of approximately $10.60 per boe supported by a $315 million capital spending program. From North Atlantic Refining, we are expecting throughput capacity to average 114,500 barrels per stream day with a crack spreads averaging US$9.30 and operating costs and capital spending of approximately $95 million and $45 million, respectively. There is no turnaround activity planned for 2007 at the refinery. Provided crude oil commodity prices remain as currently expected by the forward curve, we anticipate that our crude oil price risk management contracts will provide floor protection of approximately US$55 for the benchmark West Texas Intermediate price with a modest cost.

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	$	0.03 / Unit
CAD/USD exchange rate	$	0.90	$	0.02	$	0.20 / Unit
AECO daily natural gas price	$	7.00	$	1.00	$	0.28 / Unit
Refinery crack spread (US$/bbl)	$	9.30	$	1.00	$	0.38 / Unit
Operating Expenses (per boe)	$	10.65	$	1.00	$	0.19 / Unit

Summary of Historical Quarterly Results

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

Financial				2006						2005						2004
($000s except where noted)		Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4
Revenue, net of royalties	$	259,818	$	257,103	$	181,160	$	154,646	$	169,654	$	120,263	$	109,931	$	106,964
Net income (loss)		107,768		60,682		(33,937)		75,638		52,862		19,516		(43,070)		11,600
Per trust unit, basic2	$	1.01	$	0.60	$	(0.41)	$	1.45	$	1.09	$	0.45	$	(1.02)	$	0.29
Per trust unit, diluted2	$	0.99	$	0.60	$	(0.41)	$	1.42	$	1.08	$	0.44	$	(1.02)	$	0.27
Cash Flows1		147,471		147,010		100,971		96,431		103,508		57,217		52,687		52,870
Per trust unit, basic1	$	1.39	$	1.45	$	1.23	$	1.84	$	2.14	$	1.32	$	1.25	$	1.31
Per trust unit, diluted1	$	1.34	$	1.43	$	1.22	$	1.81	$	2.09	$	1.29	$	1.19	$	1.18
Distributions per Unit, declared	$	1.14	$	1.14	$	1.11	$	1.05	$	0.95	$	0.60	$	0.60	$	0.60
Total long term financial liabilities		1,105,728		746,840		735,896		349,074		386,124		455,163		321,534		326,250
Total assets		4,076,771		3,455,918		3,470,653		1,308,481		1,327,272	1,117,792			1,079,269	1,050,483
Total production (boe/d)		62,178		60,145		53,014		38,834		37,549		34,463		35,386		37,215
(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.

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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. 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 Policies and Critical Accounting Estimate

Critical accounting policies and estimates are the same as those presented in our 2005 annual MD&A.

Recent Canadian Accounting and Related Pronouncements

In an effort to harmonize Canadian GAAP with U.S. GAAP, the Canadian Accounting Standards Board has recently issued new Handbook sections:

• 1530, Comprehensive Income;
• 3855, Financial Instruments – Recognition and Measurement;
• 3861, Financial Instruments – Disclosure and Presentation; and
• 3865, Hedges.

Under these new standards, all financial assets should be measured at fair value with the exception of loans, receivables and investments that are intended to be held to maturity and certain equity investments, which should be measured at cost. Similarly, all financial liabilities should be measured at fair value when they are either derivatives or held for trading. Gains and losses on financial instruments measured at fair value will be recognized in the income statement in the periods they arise with the exception of gains and losses arising from:

• financial assets held for sale, for which unrealized gains and losses are deferred in other comprehensive income until sold or impaired; and

• certain financial instruments that qualify for hedge accounting.

Sections 3855 and 3865 make use of the term "other comprehensive income". Other comprehensive income comprises revenues, expenses, gains and losses that are excluded from net income. Unrealized gains and losses on qualifying hedging instruments, unrealized foreign exchange gains and losses, and unrealized gains and losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Comprehensive income and its components will be a required disclosure under the new standard. Section 3861 addresses the presentation of financial instruments and non-financial derivatives, and identifies the information that should be disclosed about them. These standards are effective for interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. As we do not apply hedge accounting to any of our derivative instruments, we do not expect these pronouncements to have a significant impact on our consolidated financial results however, our review of these pronouncements and their impact is ongoing.

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Non-Monetary Transactions

The AcSB has issued Section 3831, Non-Monetary Transactions, which replaces Section 3830, and requires all non-monetary transactions to be measured at fair value unless:

• the transaction lacks commercial substance;

• the transaction is an exchange of production or property held for sale in the ordinary course of business for production or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange;

• neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or

• the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation.

The new requirements apply to non-monetary transactions, initiated in periods beginning on or after January 1, 2006. Earlier adoption was permitted as of the beginning of a period beginning on or after July 1, 2005. This section did not have a material impact on our results of operations or financial position.

Operational and Other Business Risks

Our operational and other business risks are substantially the same as those presented in our 2005 annual MD&A with the addition of the refinery to our business effective October 19, 2006. The incremental risk factors of the refining business are fully described on page 23 of the preliminary prospectus dated October 31, 2006 and filed on www.sedar.com. The following risk management activities are being carried relative to our refinery risks and are in addition to the activities noted on Page 26 of our Annual Information Form also filed on www.sedar.com:

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 largest physical traders and marketers of crude oil and petroleum products so to minimize the risk of disruptions in supply.

Commodity Price Exposure

• Contracts will be entered into 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, so to minimize the time between the pricing of the feedstock and the refined products with the objective of maintaining margins.

Environmental, Health and Safety

• The refinery is substantially compliant with existing laws and regulations in this area and keeps apprised of any changes in this area.
• Appropriate funding is allocated to environment, health and safety to invest in programs and capital initiatives to minimize the risks in this area.

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 operational disruptions due to strikes or work stoppage.

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Non-GAAP Measures

Throughout this MD&A we have referred to certain measures of financial performance that are not specifically defined under Canadian GAAP. Specifically, we use Cash Flow as cash flow from operating activities before changes in non-cash working capital, settlement of asset retirement obligations and one time transaction costs. Cash Flow as presented is not intended to represent an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with Canadian GAAP. Management uses Cash Flow to analyze operating performance and leverage. Payout Ratio, Cash G&A and Operating Netbacks are additional non-GAAP measures used extensively in the Canadian energy trust sector for comparative purposes. Payout Ratio is the ratio of distributions to total Cash Flow. Operating Netbacks are always reported on a per boe basis, and include gross revenue, royalties and operating expenses, net of any realized gains and losses on related risk managements. Cash G&A are G&A expenses excluding the effect of our unit based compensation plans.

For the three and nine months ended September 30, 2006 and 2005, Cash Flows are reconciled to its closest GAAP measure, Cash Flow from operating activities, as follows:

	Three months ended							Nine months ended
($000s)	Sept. 30, 2006		June 30, 2006		Sept. 30, 2005		Sept. 30, 2006		Sept. 30, 2005
Cash Flow	$	147,471	$	147,010	$	103,508	$	395,452	$	213,412
Cash Viking transaction costs		(516)		(670)		-		(6,258)		-
Settlement of asset retirement obligations		(2,285)		(625)		(1,169)		(4,028)		(2,333)
Changes in non-cash working capital		(1,073)		(10,134)		29,810		(17,824)		(25,867)
Cash flow from operating activities	$	143,597	$	135,581	$	132,149	$	367,342	$	185,212

Forward-Looking Information

This MD&A highlights significant business results and statistics from our consolidated financial statements for the three and nine months ended September 30, 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; 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, operating costs, commodity prices, administrative costs, commodity price risk management activity, acquisitions and dispositions, capital spending, 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 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.

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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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