Harvest Energy Trust 40F 2005 Annual report | HTE Filing

EXHIBIT 99.3

Exhibit 99.3 – Management Discussion and Analysis

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. In this MD&A, reference to "Harvest", "we", "us" or "our" refers to Harvest Energy Trust and all of its controlled entities on a consolidated basis. The information and opinions concerning our future outlook are based on information available at March 8, 2006. When reviewing our 2005 results and comparing them to 2004, readers are cautioned that the 2005 results include a full year of operations from our 2004 acquisitions and the Hay River acquisition for five months of 2005. The combination of these events significantly impact the comparability of our operations and financial results for 2005 to the results of 2004 as well as the comparability between quarters.

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.

2005 Financial and Operating Highlights

Cash Flows for 2005 totaled $309.8 million ($6.66 per Trust Unit), a 150% increase over $123.7 million ($4.94 per Trust Unit) earned in 2004.
Distributions declared totaled $3.20 per Trust Unit in 2005 resulting in a payout ratio of 50% compared to $2.40 per Trust Unit declared in 2004 and a payout ratio of 52%.
Total return of 76% for Unitholders in 2005 comprised of 62% capital appreciation and a cash on cash yield of 14%.
Increased average daily production in 2005 by 58% to 36,571 BOE/per day with consistent year over year production per Trust Unit on a debt adjusted basis.
Capital asset additions in 2005 totaled $120.5 million compared to $42.7 million in 2004.
Finding and development (F&D) costs of $10.73/BOE on a proved plus probable ("P+P") basis, excluding future development costs and $13.10/BOE including future development costs, reflecting a recycle ratio (operating netback divided by F&D cost) of 3.1. P+P reserves per Trust Unit, on a debt adjusted basis, increased 11% year over year, and our reserve life index (RLI) increased over the same period from 7.9 to 9.4, after inclusion of the effects of the merger with Viking Energy Royalty Trust.
Improved balance sheet and financing flexibility in 2005, with debt to annualized Cash Flows of 0.9 times at December 31, 2005 compared to 1.9 times at the end of 2004. Subsequent to year end, secured a $750 million, largely undrawn 3 year term credit facility, with plans to syndicate it to $900 million by the end of March.
Completed acquisition of Hay River property for cash consideration of $237.8 million adding 5,200 bbl/day of medium grade oil production and financed it with the issuance of $75 million of convertible debentures and $175 million of equity.

Fourth quarter Cash Flow of $96.4 million which reflects a full quarter of incremental production from Hay River.
Entered into an agreement to complete a merger with Viking Energy Royalty Trust ("Viking") to consolidate the technical skills and internal development opportunities of both organizations. Following the merger, Harvest is one of Canada's largest energy royalty trusts with a balanced production base (50% light/medium oil, 25% heavy oil and 25% natural gas) and significant long-term development opportunities.

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

		Twelve months ended December 31
FINANCIAL ($000s except where noted)		2005		2004	Change
			(Restated) ⁽⁴⁾
Revenue, net⁽¹⁾		436,452		212,118	106%

Cash Flows⁽²⁾		309,843		123,710	150%
Per Trust Unit, basic⁽²⁾	$	6.66	$	4.94	35%
Per Trust Unit, diluted⁽²⁾	$	6.35	$	3.97	60%

Net income		104,946		11,241	834%
Per Trust Unit, basic	$	2.25	$	0.45	400%
Per Trust Unit, diluted	$	2.19	$	0.43	409%

Distributions declared⁽³⁾		153,494		64,563	138%
Distributions declared, per Trust Unit	$	3.20	$	2.40	33%
Payout ratio ⁽²⁾⁽³⁾		50%		52%	(2%)
Capital asset additions (excluding acquisitions)		120,508		42,662	182%

Total daily sales volumes (BOE/day)		36,571		23,136	58%


	Harvest		Harvest and Viking Proforma
	As at December 31, 2005		As at December 31, 2005
RESERVES (mBOE)	Gross	Net	Gross	Net
Proved reserves	87,731	77,557	151,591	131,882
Probable reserves	31,946	27,984	54,663	47,175
Total proved plus probable (P+P) reserves	119,677	105,541	206,254	179,057

(1) Revenues are net of royalties and risk management contracts

(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.

(4) Restated to reflect the adoption of new CICA recommendations to account for convertible debentures and exchangeable shares. See Note 3 to the Consolidated Financial Statements.

Review of Operations and Strategy

Harvest is an oil and natural gas royalty trust, which focuses on the operation of quality petroleum and natural gas properties. We employ a disciplined approach to the oil and natural gas production business, whereby we acquire high working interest, large resource-in-place, mature producing properties and employ "best practice" technical and field operational processes to extract maximum value. These operational processes include: diligent hands-on management to maintain and maximize production rates, the application of technology and selective capital investment to maximize reservoir recovery, and the enhancement of operational efficiencies to control and reduce expenses.

Overall, we had a successful year with Cash Flow for the year ended December 31, 2005 of $309.8 million ($6.66 per Unit). This 150% increase in Cash Flow compared to the prior year and is attributed to higher commodity prices, a full year of production from the acquisitions made in 2004 and incremental production from the Hay River acquisition.

Our Unitholders have received a 76% total return since the beginning of 2005, comprised of capital appreciation of 62% and a cash on cash yield of 14%.

Distribution increases were achieved while implementing a $120.5 million capital development program that was directed towards sustaining our production. Our capital development program is focused on growing and maintaining production with 94% of the costs directly related to drilling activities. We continue to focus on established resource plays that require fewer infrastructure investments. Our 2005 Finding & Development (F&D) costs before changes in future development capital ("FDC"), were $10.73 per BOE on a P+P reserve basis, and $11.80 per BOE on a Total Proved basis. Our capital program, together with our 2004 and 2005 acquisitions, contributed to a 58% increase in production from 23,136 BOE/d to 36,571 BOE/d in 2005.

We are continuously evaluating potential acquisition prospects that provide us additional development opportunities. On August 2, 2005, we closed the acquisition of the Hay River property for approximately $237.8 million. The Hay River property consists primarily of about 5,200 bbl/d of medium gravity crude produced in Northeastern British Columbia. The cost was approximately $46,000 per flowing BOE. The closing of the Hay River purchase occurred concurrently with a $250 million equity and convertible debenture financing. Our 2005 results reflect five months of production from Hay River.

The Hay River barrels sell at a premium to our average medium gravity crude oil production. The West Texas Intermediate ("WTI") realized price differential on our Hay River production was 14% while our remaining medium gravity crude production sold at an average differential of 34%. This, coupled with the impact of the lower Hay River operating expenses, improved our corporate netbacks for the year ended December 31, 2005. In the future, due to the 'winter only' access nature of this property, our first quarter results from Hay River will reflect higher operating and capital expenditures and lower production volumes than the remainder of the year. Our second quarter results should reflect the benefits of the activities undertaken in the first quarter, and as a result, the first quarter will not be indicative of the results expected for the balance of the year.

Cash Flows totaled $96.4 million (or $1.84 per Trust Unit) for the fourth quarter of 2005. This compares to fourth quarter 2004 Cash Flows of $52.9 million (or $1.31 per Trust Unit). Our 2005 exit Cash Flows nearly doubled over the prior year and reflect our higher operating netback. Our fourth quarter results provide an estimate for our future performance prior to the Viking Arrangement as this was the first full quarter including the results of our Hay River property.

On February 2, 2006, the security holders of Harvest and the Unitholders of Viking voted in favour of a resolution to effect a plan of arrangement (the "Arrangement") by which Unitholders of Viking received 0.25 Harvest Units for every Viking Unit held and Harvest acquired all of Viking's assets. As part of the Arrangement, Harvest assumed Viking's 10.5% and 6.40% unsecured subordinated convertible debentures and adjusted their conversion prices to $29.00 for the 10.5% series and $46.00 for the 6.40% series, consistent with the four to one exchange ratio under the Arrangement. At the time of writing and reflecting the Viking Arrangement, approximately 99.9 million Trust Units and approximately $252.8 million of convertible debentures are outstanding.

The Arrangement also enabled exchangeable shareholders to convert their exchangeable shares of Harvest Operations into Trust Units. As a result, 156,011 exchangeable shares were tendered, resulting in only 26,902 exchangeable shares remaining. Harvest intends to issue a notice to the remaining exchangeable shareholders to redeem these outstanding shares for cash in June 2006.

The combination of the two trusts created one of the largest conventional petroleum and natural gas trusts in North America with an initial enterprise value in excess of $4 billion. The merged entity has productive capacity of an estimated 64,000 BOE/d weighted approximately 50 percent to light and medium gravity oil, 25 percent to natural gas and 25 percent to heavy gravity oil. Although this transaction has no impact on the results for the year ended December 31, 2005, it will have a significant impact on the future results of Harvest.

REVIEW OF 2005 OPERATIONS

Commodity Price Environment	Year Ended December 31
Benchmarks	2005	2004	Change

West Texas Intermediate crude oil (US$ per barrel)	56.56	41.40	37%
Edmonton light crude oil ($ per barrel)	68.73	52.54	31%
Bow River blend crude oil ($ per barrel)	44.28	37.19	19%
AECO natural gas ($ per mcf)	8.71	6.53	33%

Canadian / U.S. dollar exchange rate	0.825	0.768	7%

The year ended December 31, 2005 saw record commodity prices and a strong Canadian dollar. The average Canadian dollar to US dollar exchange rate strengthened by 7%. This strengthening of the Canadian dollar partially offset gains in WTI for Canadian producers. While the U.S. dollar WTI strengthened by 37%, the Canadian dollar equivalent of WTI strengthened by 27%, a full 10% less than the U.S. dollar WTI equivalent. However, the differential between Edmonton light crude oil prices and WTI narrowed from 2004 to 2005, which was more than offset by widening of the Bow River differentials to Edmonton Par in 2005 compared to those realized in 2004.

	2005				2004
Differential Benchmarks	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Bow River Blend differential to
Edmonton Light	40.0%	28.2%	39.6%	36.6%	39.1%	26.2%	26.6%	23.9%

To maintain stable Cash Flow and thereby, stable distributions, we have implemented a commodity price risk management program which reduces the variability in our Cash Flow while allowing participation in price improvements. Further discussion regarding our risk management program is included under the heading "Risk Management Contracts".

Revenues

	Year ended December 31
($000)	2005	2004	% Change
Light / medium oil sales	$ 366,432	$ 202,970	81%
Heavy oil sales	197,863	96,313	105%
Natural gas sales	87,437	25,455	243%
Natural gas liquids sales and other	15,764	7,071	123%
Total sales revenue	667,496	331,809	101%
Realized risk management contract losses⁽¹⁾	(79,271)	(54,488)	45%

Net revenues including realized risk management contract losses	588,225	277,321	112%
Realized electricity price risk management contract gains	6,290	2,061	205%
Unrealized risk management contracts losses	(45,061)	(11,274)	300%
Net Revenues, before royalties	549,454	268,108	105%
Royalties	(113,002)	(55,990)	102%

Net Revenues	$ 436,452	$ 212,118	106%

(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 / medium oil sales revenue for the year ended December 31, 2005 was $163.5 million (or 81%) higher than in the prior year as a result of a favourable price variance of $77.8 million and volume variance of $85.7 million. The favourable price variance relates to higher commodity prices in the year and a change in our product mix. Edmonton par increased by 31% and Bow River increased by 19% over the prior year, which contributed significantly to the higher revenues realized for 2005. In addition, our product mix changed significantly with the acquisition of Hay River. Our average per barrel realized price for our medium grade properties, excluding Hay River, was $48.78 while our average realized per barrel price for the Hay River properties was $63.56 for the same period. Favorable volume variances are primarily due to the two significant acquisitions completed during the latter half of 2004 as well as the acquisition of the Hay River property in 2005, all of which substantially increased light / medium production volumes.

Heavy oil revenues for the year ended December 31, 2005 increased $101.6 million (or 105%) due to a favourable volume variance of $59.9 million and favourable price variance of $41.7 million. The acquisition we made in September of 2004 contributed additional heavy oil volumes and the rising crude oil price environment resulted in higher realized prices on our heavy oil.

Natural gas sales revenue increased by $62 million (or 243%) for the twelve months ended December 31, 2005 over the same period in the prior year. Record natural gas prices in 2005 resulted in a favourable natural gas sales revenue price variance of $26.4 million, and our acquisition of the Crossfield and Cavalier properties in 2004 were the primary contributors to a favourable volume variance of $35.6 million.

Natural gas liquids do not contribute significantly to our overall sales revenues. For the year ended December 31, 2005, natural gas liquids revenues increased by $8.7 million (or 123%) over the prior year, with the increase generally due to a higher pricing environment and higher production volumes resulting from our acquisitions in 2004.

Sales Volumes

The average daily sales volumes by product were as follows:

	Year ended December 31
	2005		2004		%
	Volume	Weighting	Volume	Weighting	Change
Light / medium oil (bbl/d)⁽¹⁾	17,590	48%	12,336	53%	43%
Heavy oil (bbl/d)	13,747	38%	8,495	37%	62%
Total oil (bbl/d)	31,337	86%	20,831	90%	50%
Natural gas liquids (bbl/d)	824	2%	472	2%	75%
Total liquids (bbl/d)	32,161	88%	21,303	92%	51%
Natural gas (mcf/d)	26,461	12%	10,999	8%	141%
Total oil equivalent (BOE/d)	36,571	100%	23,136	100%	58%

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

Full year 2005 average production was higher than in 2004 due to a full year of production from the 2004 acquisitions completed during the second half of 2004, as well as the incremental production from the Hay River property acquired in the third quarter of 2005. Our 2005 production was negatively impacted by unusually heavy rainfall and flooding in Alberta and Saskatchewan in the second quarter of 2005, with the impact extending to the third quarter as wet ground conditions resulted in additional downtime in many of the affected areas.

We do not intentionally manage to a specific production mix. The production mix is a result of our strategy of targeting accretive acquisitions and capitalizing on opportunities, rather than targeting specific commodity types. Our production mix in 2006 will be altered with the full year impact of the Hay River acquisition, and the completion of the Arrangement with Viking, such that approximately 50% of our production is weighted towards light / medium oil, 25% to natural gas and 25% to heavy oil.

Realized Commodity Prices

The following table provides a breakdown of our 2005 and 2004 average commodity prices by product before and after realized losses on risk management contracts.

		Year ended December 31
		2005		2004	Change
Light to medium oil ($/bbl)	$	57.07	$	44.95	27%
Heavy oil ($/bbl)	$	39.43	$	31.13	27%
Natural gas liquids ($/bbl)	$	52.40	$	40.95	28%
Natural gas ($/mcf)	$	9.05	$	6.32	43%
Average realized price ($/BOE)	$	50.01	$	39.18	28%

Realized risk management losses ($/BOE)⁽¹⁾	$	(5.94)	$	(6.43)	(8%)
Net realized price ($/BOE)	$	44.07	$	32.75	35%

(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 28% higher for the twelve months ended December 31, 2005 as compared to 2004. WTI for the same period increased by $15.16 per bbl or 37%. However, this increase was partially offset by a stronger Canadian dollar. The Canadian dollar increase in WTI was significantly lower at 27% which is consistent with the increase on our total realized prices per BOE of 28%.

For the latter half of 2005, our realized prices also reflected the change in our production mix. For the first seven months of the year approximately 45% of our production was priced off of the Bow River Stream, which is generally considered a medium oil stream, and approximately 11% was priced off the light oil benchmark, Edmonton Par. Subsequent to acquiring Hay River, our product pricing was more heavily weighted towards Edmonton Par at approximately 25% and less heavily weighted towards Bow River Pricing at approximately 36%. This change has resulted in a higher overall realized price as the production from our Hay River property is sold through a light oil pipeline at a premium price relative to our other medium properties. Despite this change in product mix in 2005, we realized wider price differentials compared to benchmark prices than we did in 2004. This is due to a general widening of benchmark differentials for lower gravity crude oil in 2005 relative to 2004.

The impact of wider differentials was particularly evident in the realized prices for our light / medium production. The differential on our light / medium realizing prices relative to Edmonton Par widened in 2005 to 17.0% from 14.4% in 2004, despite our Hay River property realizing a higher price than our other medium gravity oil production. This widened price differential is primarily explained by the higher average Bow River differential to Edmonton Par of 36% compared to 29% in 2004. The remainder of the difference is due to the 7% higher weighting of medium oil production in 2005 than in 2004, which would result in an overall lower differential to Edmonton Par in 2004 than in 2005 for our light / medium oil.

Our average heavy oil price differential compared to Bow River narrowed from 16.3% in 2004 to 11.0% in 2005 as our realized sales prices relative to benchmarks has generally been higher in 2005, due to stronger market premiums for Bow River crude oil.

In 2005, heavy oil differentials narrowed between May and August and our heavy gravity crudes were positively impacted as a result. Towards the end of the third quarter and more significantly in the fourth quarter, heavy oil differentials widened and crude oil prices were somewhat lower. This was expected as heavy oil differentials usually widen in the fourth quarter due to seasonal demands. Edmonton Par decreased by 7% from the third quarter to the fourth quarter, while Bow River prices decreased by 22%.

Over the past 20 years the benchmark heavy differential has averaged very close to 29% of WTI. Due to the volatility in heavy oil differentials we have entered into differential hedges to partially shelter us from this volatility. Further discussion on these hedges is contained under the heading "Risk Management Contracts" of this MD&A.

Risk Management Contracts

All of our hedging activities are carried out pursuant to policies approved by the Board of Directors of Harvest Operations Corp. Management intends to facilitate stable, long-term monthly distributions by reducing the impact of volatility in commodity prices. As part of our risk management policy, management utilizes a variety of financial instruments to manage commodity price, heavy oil price differentials, foreign currency and interest rate exposures. These instruments are commonly referred to as 'hedges' but may not receive hedge treatment for accounting purposes. Management also enters into long term fixed price electricity purchase contracts to assist in maintaining stable operating costs. We reduce our exposure to credit risk associated with these financial instruments by only entering into transactions with financially sound, credit-worthy counterparties. Our risk management contracts at December 31, 2005 consist of indexed puts, participating swaps, collars, fixed price heavy oil differential and electricity price purchase contracts.

The table below provides a summary of net gains and losses on risk management contracts during 2005 and 2004:

						Years ended
						December
	Year ended December 31, 2005					31, 2004
($thousands)	Oil	Gas	Currency	Electricity	Total	Total

Realized (losses) / gains on risk
management contracts	(80,677)	-	1,406	6,290	(72,981)	(52,427)
Unrealized (losses) / gains on risk
management contracts	(41,360)	378	(3,488)	8,389	(36,081)	3,322
Amortization of deferred charges relating
to risk management contracts	(10,759)	-	-	-	(10,759)	(14,946)
Amortization of deferred gains relating to
risk management contracts	-	-	-	1,779	1,779	350
Total (losses) / gains on risk management
contracts	(132,796)	378	(2,082)	16,458	(118,042)	(63,701)

Our total realized loss on oil price and foreign exchange risk management contracts increased to $79.3 million (or $5.94 per BOE) for the year ended December 31, 2005 compared to $54.5 million (or $6.43 per BOE) for the year ended December 31, 2004, due to the significant increases in commodity prices in 2005 compared to 2004 as well as higher volumes committed under risk management contracts. This loss effectively represents the cost of insurance to provide price protection from commodity price downturns. The decrease in the loss per BOE, despite higher commodity prices, is due to a change in our hedging strategy. This increase was slightly offset by gains on our currency exchange positions as the Canadian dollar traded below $1.20 per $1 U.S. in 2005, which enabled us to realize gains.

In the first half of 2005, a significant portion of our hedging contracts had fixed ceilings such that in an increasing pricing environment, our losses increased dollar for dollar as the WTI price increased. We have substantially changed our hedging strategy to provide firm floors with upside participation. Examples of such contracts include 'indexed puts' and 'participating swaps'. At December 31, 2005, all price contracts with fixed ceilings have expired. As a result, for the year ended December 31, 2006, our realized losses on our oil price risk management contracts will most likely be less than if we continued to use price contracts with fixed ceilings. The 2006 contracts also have higher average floor prices. Price contracts with fixed ceilings such as swaps and collars represented $3.56/BOE (or $47.5 million) of the total realized loss of $5.94 per BOE (or $79.3 million) in 2005. The total loss on our indexed puts for the year ended December 31, 2005, was $37.0 million (or $2.78 per BOE).

Our realized losses on oil risk management contracts have been partially offset by gains on our heavy oil differential hedges. We have taken steps to mitigate the impact of wider differentials on a portion of our heavy crude oil by fixing the differentials as a percentage of WTI at an average 28% of WTI. These transactions became effective in July of 2005 on 10,000 bbl/d and extend through December of 2006. For the year ended December 31, 2005, these heavy oil differential hedges represented a gain of $0.29/BOE or $3.9 million.

For the 2005 fiscal year, we did not hedge natural gas prices. Similar to WTI prices, natural gas prices rose consistently through 2005 from a low of $5.71 US/MMBtu on January 3, 2005 to a high of $15.78 US/MMBtu on December 13, 2005. In 2005, our natural gas was sold almost exclusively at a price that moves with the benchmark AECO "C" hub prices. In the fourth quarter of 2005, we entered into a natural gas collar on 5,000 GJ/day with a floor of $9.00/GJ and a ceiling of $13.06/GJ, that will provide us with price protection from April 2006 to October 2006.

We have also entered into risk management contracts which provide us protection on rising power costs. We have realized gains on these contracts of $6.3 million (or $0.47 per BOE). Additional details on these contracts is provided under the heading "Operating Expense" of this MD&A.

The unrealized losses on our risk management contracts for the year ended December 31, 2005 were $45.1 million or ($3.38 per BOE). For the year ended December 31, 2004, unrealized losses on risk management contracts were $11.3 million or $1.33 per BOE. As of October 1, 2004, we ceased to apply hedge accounting to our risk management contracts. As a result, from October 1, 2004, all of our hedging instruments are marked-to-market as at the balance sheet date with the resulting gain or loss reflected in earnings in the respective accounting period as an unrealized gain or loss on risk management contracts. The fair market valuation represents the amount that would be required to settle each contract on the period end date and is determined using prices from actively quoted markets.

Collectively, our risk management contracts had an unrealized mark-to-market deficiency of $52.6 million as at December 31, 2005. The difference between this value and the mark-to-market amount at December 31, 2004 ($15.4 million) is included in our unrealized loss in the twelve month period ended December 31, 2005. Please refer to Note 16 to the consolidated financial statements for further details of the financial instruments outstanding at December 31, 2005. Also included in our unrealized losses is the amortization of the deferred charges and credits that were deferred when we ceased to apply hedge accounting. This represented $9.0 million of our total unrealized gains and losses on risk management contracts for 2005 and $14.6 million for 2004. 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. In certain situations, such as with some heavy oil production, the Alberta Energy and Utilities Board grants royalty 'holidays', effectively eliminating royalties on a specific well or group of wells.

For the full year 2005 and 2004, our net royalties as a percentage of revenue were 16.9%, which represented $113.0 million and $56.0 million, respectively. Increases in the royalty rate were expected due to the higher rates associated with the Hay River property acquired in August 2005, and a 3.6% surcharge on gross revenue applied by the Saskatchewan government on gross resource revenues earned in Saskatchewan (2% for production from wells drilled subsequent to October 2002). This is a result of a recent change in the Saskatchewan legislation whereby trusts become subject to the same surcharge that applies to corporations effective April 1, 2005. We estimate the blended rate applied to our Saskatchewan properties will be approximately 3.1% of Saskatchewan revenue which makes up approximately 20% of our total production prior to the Viking Arrangement. The expected increases in royalty rates were offset by royalty 'holidays' realized in Saskatchewan due to more drilling activity in 2005 than in 2004. In addition, we also benefited from higher Alberta Royalty Tax Credits than initially anticipated.

For 2006, we are anticipating our royalty rate as a percentage of net revenues to be approximately 19.5%, considering the addition of the Viking assets.

Operating Expense

	Year Ended December 31
									Per BOE
($thousands)		2005		Per BOE		2004		Per BOE	Change
Operating expense
Power	$	39,452	$	2.96	$	27,097	$	3.20	(9%)
Workovers		25,791		1.93		10,581		1.25	54%
Repairs and maintenance		10,478		0.79		4,504		0.53	49%
Labour – internal		7,631		0.57		4,551		0.54	6%
Fuel		6,451		0.48		2,068		0.24	100%
Labour – external		5,917		0.44		1,407		0.17	159%
Land leases		5,306		0.40		2,827		0.33	21%
Other		26,232		1.97		20,407		2.41	(18%)
Total operating expense		127,258		9.54		73,442		8.67	10%
Realized gains on power risk management contracts		(6,290)		(0.47)		(2,061)		(0.24)	96%
Net operating expense	$	120,968	$	9.07	$	71,381	$	8.43	8%

Total operating expense increased by $53.8 million (or 73%) for the year ended December 31, 2005 compared to the prior year. Approximately $44.0 million of the increase for the year ended December 31, 2005 is due to increased activity associated with acquisitions made in 2004 and 2005. The remainder of the increase is attributed to fuel cost increases, and unprecedented demand for oilfield services leading to higher costs for well servicing, workovers and well maintenance. In addition, weather related delays in servicing negatively impacted production for the year resulting in lower relative production volumes. Overall, we expect to continue to see higher operating costs as a result of general cost pressures in the oil and natural gas industry. To help control operating expenses, a portion of our capital spending program is directed towards operating cost reduction initiatives such as water disposal, fluid handling and power reduction projects. We strive to minimize operating costs, which contributes to stronger netbacks, and can extend reserve life by making the extraction of reserves more economical later in the life of the property.

As noted, electricity costs represent a significant portion (approximately 31%) of our operating costs and with rising electricity prices, particularly in Alberta, our operating expenses can be significantly impacted. On average, our Alberta electricity costs per megawatt hour ("MWh") were 33% higher in 2005 than they were in 2004. These increases were offset by the impact of the 2004 and 2005 acquisitions, which included properties that have lower average per BOE power usage than the properties held prior to the acquisitions. Power prices skyrocketed to average $116/MWh in the fourth quarter of 2005, the highest average quarterly price since the fourth quarter of 2000. In 2005, the average price for the year was $70.35/MWh, the highest annual average since 2001. Our fixed price purchase contracts have enabled us to partially offset rising electricity costs. The following table details the power costs per BOE before and after the impact of our hedging program.

	Year ended December 31
($ per BOE)		2005		2004	Change
Power costs	$	2.96	$	3.20	(7%)
Realized gains on electricity risk management contracts		(0.47)		(0.24)	96%
Net power costs	$	2.49		2.96	(16%)

Approximately 79% of our estimated Alberta electricity usage is protected by fixed price purchase contracts at an average price of $49.15 per MWh through December 2006. Of our estimated 2007 and 2008 Alberta electricity usage, 61% 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 2005 and future periods that are dedicated to increasing our power efficiency.

	Year Ended December 31
		2005		2004	Change
Alberta Power Pool electricity price ($ per MWh)	$	70.35	$	54.59	29%


Operating Netback

	Year Ended December 31
Operating Netback⁽³⁾ ($/BOE)		2005		2004	Change
Revenues	$	50.01	$	39.18	28%
Realized loss on risk management contracts⁽¹⁾		(5.94)		(6.43)	(8%)
Royalties		(8.47)		(6.61)	28%
As a percent of revenue		16.9%		16.9%	-
Operating expense⁽²⁾		(9.07)		(8.43)	7%
Operating netback⁽³⁾	$	26.53	$	17.71	56%

(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 $0.47 per BOE for the full year 2005 and $0.24 per BOE for the same period in 2004.

(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 $8.83 per BOE higher in 2005 than the prior year as a direct result of our recent acquisitions and events discussed above, with the single largest factor being higher commodity prices.

General and Administrative (G&A) Expense

	Year ended December 31
($000s except per BOE)		2005		2004	Change
Cash G&A⁽¹⁾	$	13,571	$	7,345	85%
Unit based compensation expense
Non-cash		16,302		9,535	70%
Cash		824		1,824	(55%)
Total G&A	$	30,697	$	18,704	64%
Cash G&A per BOE ($/BOE)		1.02		0.87	17%

(1) Cash G&A excludes the impact of our unit based compensation expense.

On a year-over-year basis, Cash G&A increased by $6.2 million (or 85%) over 2004 due to higher staffing levels in 2005. The majority (approximately 62% or $8.5 million) of our 2005 Cash G&A expenses are related to salaries and other staffing costs while in 2004, these staffing costs were 63% or $4.6 million of our Cash G&A expenses. In the latter half of 2004, we made two significant acquisitions that increased our overall staffing levels. These higher staffing levels impacted the entire year in 2005 as compared to a partial year in 2004. In addition to higher staffing levels, we incurred the one time and recurring costs related to our New York Stock Exchange listing, as well as higher insurance costs, professional services fees and costs associated with the evaluation of potential acquisition opportunities.

In an effort to minimize dilution, our unit based compensation plans provide the employee with the option of settling outstanding awards with cash. Our cash unit right compensation expense for the twelve months ended December 31, 2005 decreased by $1 million from the prior year. The timing of exercises for cash is not consistent from period to period. The increase in non-cash unit right compensation expense of $6.8 million for the twelve months ended December 31, 2005 is a result of a higher market price for our Trust Units. As our non-cash unit appreciation rights ("UAR") expense is determined based on the difference between the exercise price and the market value of the vested UARs at the end of each reporting period, an increasing Unit price has a significant impact on our non-cash UAR expense.

In 2006, we expect total cash G&A expenses to average approximately $1.25 on a per BOE basis. Although we anticipate efficiencies from the Viking Arrangement to ultimately reduce G&A per BOE in the medium to longer term, we expect some incremental costs associated with integration in the short-term. In addition, due to the immediate vesting of the rights and awards issued under our unit based compensation plans as a result of the Arrangement with Viking, we will also realize large increases in our unit based compensation expense in the first quarter of 2006.

Interest Expense

	Year ended December 31
		2005		2004	Change
($000s)			(restated)
Interest on short term debt	$	4,089	$	6,781	(40%)
Amortization of deferred charges – short term debt		2,498		3,734	(33%)
Total interest on short term debt		6,587		10,515	(37%)

Interest on long-term debt
Senior notes		23,952		5,117	368%
Convertible debentures		2,865		5,248	(45%)
Bank loan		651		-	100%
Amortization of deferred charges – long term debt		2,356		818	188%
Total interest on long term debt		29,824		11,183	167%
Total interest expense	$	36,411	$	21,698	68%

Interest expense for the twelve months ended December 31, 2005 was $14.7 million higher than for the same period in the prior year primarily due to paying interest on the senior notes for a full year and lower interest on short term debt due to a lower average short term debt balance during the year than in the prior year.

Interest expense reflects the charges on our outstanding bank debt, convertible debentures and senior notes as well as amortization of related financing costs. Interest on our bank debt is levied at the prime rate plus 0 to 2.25% depending on our debt to Cash Flows ratio. We assumed approximately $100 million of bank debt on the merger with Viking which will increase future interest charges compared to the fourth quarter of 2005. However, we have also negotiated a new credit facility in February 2006 which has lower interest margins than our previous facility.

Our outstanding convertible debentures have fixed interest rates at 9% for the first series (issued in January 2004), 8% for the second series (issued in August 2004) and 6.5% for our third series (issued in August 2005). However, interest for the convertible debentures is reported based on the effective yield of the debt component of the convertible debentures. The large number of conversions of convertible debentures during 2005 were primarily the higher interest rate debentures and will result in lower interest charges for these remaining debentures in 2006 than in 2005. However, under the Viking Arrangement, we assumed Viking's 10.5% ($35 million) and 6.40% ($175 million) unsecured subordinated convertible debentures. The assumption of these convertible debentures will more than offset the 2005 reduction in interest charges. Our U.S. dollar denominated senior notes, which bear interest at 7 7/8%, mature on October 15, 2011 and have a fourth year redemption feature, provide an offset to fluctuations in currency exchange rates. Interest expense in 2006 on the senior notes should remain relatively consistent with 2005 with any fluctuations being attributed to volatility in Canadian dollar to U.S. dollar exchange rates.

A portion of the total interest expense recorded is non-cash ($535,000 for 2005 and $100,000 for 2004) relates to 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.

Depletion, Depreciation and Accretion Expense

		Year ended December 31
($000s except per BOE)		2005		2004	Change
Depletion and depreciation	$	155,841	$	88,777	75%
Depletion of capitalized asset retirement costs		14,345		9,778	47%
Accretion on asset retirement obligation		8,770		4,221	108%
Total depletion, depreciation and accretion	$	178,956	$	102,776	74%
Per BOE ($/BOE)	$	13.41	$	12.14	10%

Our overall depletion, depreciation and accretion (DD&A) rate per BOE for the year ended December 31, 2005 is higher compared to the same period in 2004 primarily due to incremental production from the acquisitions made in the latter half of 2004 and 2005. The higher DD&A rate reflects a slightly higher per Unit amortization charge from these acquisitions.

Foreign Exchange Gain

Foreign exchange gains and losses are attributable to the effect of 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 U.S. dollar deposits and cash balances. Our senior notes, which were issued in October 2004, reduce our net exposure to fluctuations in foreign exchange rates by offsetting the impact on net oil prices realized.

The largest portion of our foreign exchange gains and losses are directly related to our U.S. dollar denominated senior notes. In the year ended December 31, 2005, the Canadian dollar strengthened against the U.S. dollar, and we incurred unrealized gains on our senior notes of $9.7 million, which was partially offset by realized losses on U.S. dollar deposit and other U.S. denominated transactions. In the year ended December 31, 2004 we recorded a gain of $7.1 million, again largely related to the strengthening Canadian dollar from the time we issued the senior notes.

Deferred Charges and Credits

The deferred charges balance on the balance sheet is comprised of three main components: deferred financing charges, discount on senior notes and deferred charges related to the discontinuation of hedge accounting. The deferred financing charges relate primarily to the issuance of the senior notes, convertible debentures and bank debt and are amortized over the life of the corresponding debt. The following table provides a summary of the components of the deferred charges at year end 2005 as compared to 2004.

($000s)	As at December 31, 2005				As at December 31, 2004
	On Dis-				On Dis-
	continuation		Discount		continuation	Financing	Discount
	of Hedge	Financing	on Senior		of Hedge	Costs	on Senior
	Accounting	Costs	Notes	Total	Accounting	(restated)	Notes	Total
Opening Balance	10,759	12,781	2,000	25,540	-	1,989	-	1,989
Additions	-	5,207	-	5,207	25,705	20,971	2,075	48,751
Transferred to				-				-
unit issue
costs on
conversion
of
debentures	-	(2,071)	-	(2,071)	-	(5,721)	-	(5,721)
Amortization	(10,759)	(4,853)	(296)	(15,908)	(14,946)	(4,458)	(75)	(19,479)
Closing Balance	-	11,064	1,704	12,768	10,759	12,781	2,000	25,540

We discontinued the use of hedge accounting for all of our risk management contracts effective October 1, 2004. For contracts where hedge accounting had previously been applied, a deferred charge and a deferred credit was recorded equal to the fair value of the contracts at the time hedge accounting was discontinued, and a corresponding amount was recorded as a risk management contracts asset or liability. The deferred amount is recognized in income in the period in which the underlying transaction is recognized.

The deferred credit balance relating to the discontinuation of hedge accounting at December 31, 2005 was $398,000 (2004 - $2.2 million). This amount will be fully amortized to income by the end of 2006. The deferred credit balance on the consolidated balance sheet also includes a leasehold improvement credit of ($991,000), 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 the residual amount that results when the purchase price of an acquired business exceeds the fair value for accounting purposes of the net identifiable assets and liabilities of that acquired business. In June 2004, we completed a Plan of Arrangement with a public oil and natural gas company, and acquired certain oil and natural gas producing properties in North Central Alberta for total consideration of $192.2 million. This transaction has been accounted for using the purchase price method, and resulted in Harvest recording goodwill of $43.8 million in 2004. This 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. No goodwill was recorded in association with the Hay River acquisition in August 2005 as the fair value of assets acquired approximated the total consideration paid.

Future Income Tax

The future income tax liability reflects the net tax effects of temporary differences between the carrying amounts of assets and liabilities of our corporate operating subsidiaries for financial reporting purposes and their corresponding income tax bases. Future income taxes arise, for example, as depletion and depreciation expense recorded against capital assets differs from claims under related tax pools. Future taxes also arise when tax pools associated with assets acquired are different from the purchase price recorded for accounting purposes. We recorded a future income tax recovery of $32.4 million for the year ended December 31, 2005, and a recovery of $10.4 million for the year ended December 31, 2004. The significant increase in the future income tax recovery for the year ended December 31, 2005, despite positive earnings before taxes in the period, is due to the earnings by flow through entities of the Trust. The corporate subsidiaries of the Trust recorded an accounting loss in 2005.

Asset Retirement Obligation (ARO)

Effective January 1, 2004, we adopted a new Canadian accounting standard for the Accounting for Asset Retirement Obligations. In connection with a property acquisition or development expenditure, we record the fair value of the ARO as a liability in the year in which an obligation to reclaim and restore the related asset is incurred. 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.

As part of our periodic review of the assumptions used to determine our ARO, we have revised our initial estimate to reflect changes in costs, the anticipated timing of expenditures, as well as changes in our credit standing and additional knowledge obtained from operating the properties for a longer period of time. As a result of this review, and property acquisitions and drilling activity in the year, our asset retirement obligation has increased by a net amount of $20.6 million in 2005 from the estimate in 2004.

Non-Controlling Interest

At December 31, 2005, we recorded a non-controlling interest amount on our consolidated balance sheet of $3.2 million. 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.

The total number of exchangeable shares converted in the year ended December 31, 2005 was 272,578, leaving a balance of 182,969 outstanding at December 31, 2005 compared to a balance of 455,547 at December 31, 2004. The exchange ratio at December 31, 2005 was 1:1.17475, which would result in an additional 214,943 Trust Units issued if all of the exchangeable shares were converted at the end of the year. Under the Arrangement with Viking, exchangeable shareholders were able to convert their exchangeable shares of Harvest Operations into Trust Units. As a result, 156,011 exchangeable shares were tendered, resulting in approximately 26,902 exchangeable shares remaining. Subsequent to the year end, we intend to issue a redemption notice to the remaining exchangeable shareholders to fully redeem their outstanding shares by the end of the second quarter of 2006.

The total net income attributed to non-controlling interest holders for years ended December 31, 2005 and 2004 was $149,000 and $225,000, respectively.

Related Party Transactions

For the year ended December 31, 2004, the Trust had obligations under equity bridge notes issued by one of our directors and a corporation controlled by that director. The notes were repaid prior to December 31, 2004.

Liquidity and Capital Resources

At the end of 2004, Harvest had bank borrowings totaling $75.5 million and undrawn credit capacity of $249.5 million, both pursuant to a $325 million revolving credit facility maturing on June 1, 2005. During 2005, Harvest earned Cash Flows totaling $309.8 million and incurred capital expenditures of $120.5 million, leaving Cash Flows after capital expenditures of $189.3 million to fund distributions. In 2005, Harvest declared distributions totaling $153.5 million (excluding the $10.7 million special distribution settled with the issuance of Trust Units) representing 50% of our Cash Flows, resulting in $35.8 million available for general corporate purposes. However in 2005, Harvest's Unitholders elected to direct $36.2 million of distributions paid to the distribution reinvestment programs resulting in retained Cash Flows after this reinvestment of $72.0 million.

On August 2, 2005, we completed our acquisition of Hay River with total cash consideration of $237.8 million. To fund the closing of this acquisition, we initially drew the funds from our existing $400 million revolving credit facility and subsequently reduced our borrowings with $239.0 million of net proceeds raised with the issue of 6,505,600 Trust Units (gross proceeds of $175.0 million) and the issue of 75,000, 6.5% Convertible Extendible Unsecured Subordinated Debentures (gross proceeds of $75.0 million).

The terms of the $400 million revolving credit facility in place during the 2005 year enabled funds to be borrowed, repaid and re-borrowed throughout the revolving period. This credit facility would have expired on July 31, 2006 but was extendable for an additional 364 day period on an annual basis with the consent of the lenders. If the term was not extended, the credit facilities would convert to a 366 day non-revolving term loan with no repayment due until August 2007. The facility was secured by a $750 million charge over all of the assets of our operating subsidiaries and a guarantee from Harvest Energy Trust. The credit agreement prescribes an applicable interest rate that floats with market conditions, includes a margin that fluctuates based on our bank debt to Cash Flows ratio (as defined in the credit agreement) and contains covenants including a borrowing base limitation and semi-annual borrowing base review.

The issuance of 2,428,606 Trust Units on the conversion of $53.8 million of principle amount convertible debentures further strengthened our balance sheet in 2005. This compares with 8,742,399 Trust Units issued on the conversion of $134.1 million of principle amount in 2004. This accelerated rate of converting debentures to Trust Units reflects the increases in the per Unit distributions as well as the capital appreciation of the Trust Units (closing price on the TSX of $37.19 at December 30, 2005 compared to $22.95 on December 31, 2004).

At the end of 2005, we had bank borrowings totaling $13.9 million, undrawn credit capacity of $386.1 million and a $400 million revolving credit facility maturing on July 31, 2006. At December 31, 2005, our total debt as a percentage of total capitalization was 35.8% (31.3% excluding the convertible debentures from total debt) while our total debt to our annualized

Fourth Quarter Cash Flow ratio was .91 (.79 excluding the convertible debentures from total debt). We consider these financial metrics to be aligned with our industry peers in the conventional oil and natural gas royalty trust sector.

Subsequent to our Arrangement with Viking, our financial profile will not be materially changed from a financial ratio standpoint. However, the increased size of the combined entity will provide improved access to capital whether it be bank credit, term debt or equity. The combined entity will have a more balanced production profile and we plan to invest $250 million in the development of our existing asset base in 2006. Our intent is to substantially replace our annual production. See our 2006 Outlook for more complete guidance on future expectations.

Concurrent with the closing of our Arrangement with Viking, we closed a $750 million extendible three year revolving credit facility with improved borrowing margins and more flexible covenant based terms. This facility has been syndicated with five Canadian chartered banks and at this time, is being further marketed to additional lenders to broaden the base of lenders as well as increase the total credit facility to a target of $900 million.

We are currently rated by Standard & Poor's as a "B+" long term credit and we are currently on "Creditwatch Positive" following the announcement of our Arrangement with Viking. Moody's Investors Service has maintained its "B2" corporate family rating on us. When they placed us on "CreditWatch Positive", Standard & Poor's recognized the improvement in our business profile as a consequence of the increase in proved reserves and production levels, as well as the improved internal replacement opportunities.

During 2005, our foreign ownership grew to approximately 40% by December 31, 2005. Contributing to this increase in foreign ownership was the listing of our Trust Units on the New York Stock Exchange ("NYSE") in July 2005. Relative to our 2005 average daily trading volume on the Toronto Stock Exchange ("TSX") of 220,000 units per day, the NYSE daily trading volume averaged 230,000 Units per day. The Arrangement with Viking resulted in reducing our foreign ownership reducing to approximately 30%, as Viking's foreign ownership was approximately 20% at the time of the merger. In 2006, we anticipate that the NYSE listing will continue to attract U.S. investors and that our percentage of foreign ownership will continue to increase as has been the trend for other interlisted energy trusts. This improved liquidity should further enhance the currency value of our Trust Units to the benefit of all Unitholders.

For 2006, we anticipate that we will continue to have adequate liquidity to fund our capital spending program and planned distributions of our Cash Flow. Harvest's historically higher Unitholder participation in our distribution reinvestment plan further provides us with opportunities to reinvest Cash Flow toward operating and capital spending or debt repayment.

Contractual Obligations and Commitments

	Maturity
Annual Contractual Obligation ($ thousands)	Total	Less than 1 year	1-3 years	4-5 years	After 5 years
Long-term debt	304,619	-	13,869	-	290,750
Interest on long-term debt^(d)	133,647	23,590	46,198	45,793	18,066
Interest on convertible debentures^(c)	15,151	3,159	6,317	2,987	2,688
Operating and premise leases	9,521	2,238	4,056	3,227	-
Capital commitments^(e)	4,936	4,936	-	-	-
Asset retirement obligations^(f)	372,464	4,300	13,208	5,361	349,595
Total	840,338	38,223	83,648	57,368	661,099

(a) As at December 31, 2005, we had entered into physical and financial contracts for production with average deliveries of approximately 24,990 barrels of oil equivalent per day in 2006 and 7,500 barrels per day in 2007. We have also entered into financial contracts to minimize our exposure to fluctuating electricity prices. Please see Note 16 to the consolidated financial statements for further details.

(b) Assumes that the outstanding convertible debentures either convert at the holders' option or are redeemed for Units at our option.

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

(d) Assumes no change in bank debt from December 31, 2005 and a constant foreign exchange rate.

(e) Relates to drilling and seismic commitments.

(f) 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

	Year Ended December 31
($000s)	2005	2004
Land and undeveloped lease rentals	$ 1,838	$ 825
Geological and geophysical	285	525
Drilling and completion	80,170	22,958
Well equipment, pipelines and facilities	32,644	13,945
Capitalized Cash G&A expenses	3,830	3,580
Furniture, leaseholds and office equipment	1,741	829
Total capital expenditures	$ 120,508	$ 42,662

Harvest incurred $120.5 million of expenditures to drill 94 gross wells in 2005 compared to $42.7 million and 31 gross wells in the prior year. The increase in activity reflects our increased focus on internally developed projects to exploit opportunities arising from our successful acquisitions, as well as significantly improved economics. The WTI benchmark price for crude oil averaged US$56.56 in 2005 compared to US$41.40 in 2004, a year-over-year increase of over 37%. Harvest's 2005 capital program was a $77.8 million increase over the prior year and resulted in the addition of 8.2 million BOE to Harvest's Proved plus Probable reserves and a 2005 F&D cost, including adjustments for changes in future development capital, of $13.10 per BOE. This compares to 9.2 million BOE added in 2004 at a cost of $4.15 per BOE. As well as reflecting the general cost pressures of western Canada's oil industry, our 2005 F&D costs are more comparable to the results of our 2003 capital program (F&D costs of $11.60 per BOE) than our 2004 F&D costs, which include a significant uplift for revisions of estimates.

In 2005, our activity was focused on our heavy oil operations at Suffield (26 gross wells) and East Hayter (16 gross wells) as well as light oil opportunities at Hazelwood in southeast Saskatchewan (15 gross wells). At Suffield, the 26 wells included 14 successful wells and one dry well from this ongoing exploitation of existing oil pools. In addition, two new pool discoveries at Suffield added 11 successful delineation and development horizontal wells. At Hayter, one vertical and fifteen horizontal wells were drilled successfully extending the NW and SE oil field boundaries as part of a continuing program to fully develop the field. At Hazelwood, ongoing exploitation of the light oil Tilston play resulted in the drilling of one dry well and 18 successful horizontal wells. This included full development of a 2004 new pool discovery.

The following summarizes Harvest's participation in gross and net wells drilled during 2005:

	Total Wells		Successful Wells		Abandoned Wells
Area	Gross	Net	Gross	Net	Gross	Net
Suffield	26	26	25	25	1	1
East Hayter	16	13	16	13	-	-
Hazelwood	19	19	18	18	1	1
Other Areas	33	25	30	24	3	3
Total	94	83	89	80	5	3

Distributions to Unitholders and Taxability

During 2005, we declared $3.20 per Trust Unit ($153.5 million, excluding the settlement of a special one-time trust unit distribution relating to undistributed 2004 taxable income of $10.7 million) to Unitholders. This represents an increase from the distribution level declared to Unitholders through 2004 of $2.40 per Trust Unit ($64.6 million). The aggregate of

distributions declared reflects the increase in distributions on a per Trust Unit basis in 2005 as well as a greater number of Units outstanding following the August equity issue and the ongoing conversion of the 9%, 8% and 6.5% series of convertible debentures and the exchange of exchangeable shares. Retained Cash Flows will continue to be used to fund debt repayment, capital development investments and possible future acquisition opportunities.

	Year ended December 31
($000s except per Trust Unit amounts)	2005	2004	% Change
Distributions declared⁽¹⁾	$ 153,494	$ 64,563	138%
Per Trust Unit	3.20	2.40	33%
Taxability of distributions (%)	100%	100%	-
Per Trust Unit	3.20	$ 2.40	33%
Payout ratio (%)	50%	52%	(2%)

(1) Excludes $10.7 million special distribution

Of the total distribution amount paid in 2005, $36.2 million was reinvested by Unitholders through the issuance of 1.2 million Trust Units under the Distribution Reinvestment Plan ("DRIP") and the Premium Distribution^TM Plan. This reflects an annual average of 24% participation under these Plans. However, the Premium component was launched in August 2005 and participation increased to approximately 40% for the latter part of 2005. Enrollment in either the distribution reinvestment or Premium Distribution component also enables Unitholders to make additional cash purchases of Trust Units directly from treasury through the Optional Trust Unit Purchase Plan. Both the DRIP Plan and Premium Distribution^TM Plan reduce the net cash outlay we are required to make on a monthly basis. Management anticipates that for 2006, participation in the DRIP Plan will be approximately 40%, the same level as had been experienced since the introduction of the Premium Distribution Plan in August 2005. 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. Under the Trust indenture, an amount equal to all undistributed royalty, interest and dividend income together with taxable and non-taxable portions of any capital gains realized by the Trust in the year, net of deductible trust expenses, will be payable to the Unitholders. As such, it is unlikely that the Trust will pay income taxes. However, the Trust's wholly-owned corporate subsidiary is subject to large corporations tax. The large corporations tax is currently scheduled to be eliminated by 2008 with the rate reducing from 0.175% in 2005 to 0.125% in 2006.

Outlook

Following our merger with Viking, Harvest is an entity of roughly twice the size with some significant benefits of size but also with many of the same challenges. In 2006, we have significant balance sheet capacity with over $600 million of undrawn credit coupled with a market capitalization of approximately $3.5 billion. Since the completion of the merger, the daily trading volume in our Trust Units on the Toronto Stock Exchange (the "TSX") and the NYSE totals approximately 1,000,000 Trust Units, representing over $30 million of daily liquidity. This liquidity along with our Trust Units being included in the S&P / TSX index enhances the attractiveness of our Trust Units to institutional investors which should improve the currency value of the Trust Units. A solid valuation is critical to our ability to compete for future acquisitions.

We anticipate that the market for Western Canadian petroleum and natural gas assets valued in the $150 million to $350 million range will continue to be in short supply and hotly contested with participation from a wide range of junior exploration and development companies, private equity capital as well as most other royalty trusts. However, we anticipate that while the more costly asset packages will also be in short supply, the competition will be significantly reduced to fewer corporations and a limited number of larger royalty trusts, such as Harvest. We will continue to be active in evaluating petroleum and natural gas acquisition opportunities which provide a large resource base, significant incremental development potential and access to an established processing and transportation infrastructure. We will likely finance the acquisition of such growth opportunities with some combination of our existing credit facilities along with the issue of longer term debt and Trust Units.

We intend to continue to be an active participant in the rationalization and consolidation of the Canadian royalty trust sector with an expectation of maintaining our current status as one of the largest trusts in our sector. The currency value of our Trust Units will be the fundamental determinant in the benefit of a trust-on-trust merger as these transactions are typically negotiated based on market valuations with premiums, if any, being nominal.

We view the sustainability of the royalty trust business model from both a financial and operational perspective. Over the long term, our sustainability will be dependent on our ability to replace production with a capital spending program, as well as pay our distributions to Unitholders entirely from Cash Flows. Following our $120.5 million of capital spending while maintaining a 50% payout ratio in 2005, we are planning a $250 million capital program for 2006. The 2006 capital program is primarily an infill drilling program with significant activity planned for our Hay River, Markerville, Suffield and southeast Saskatchewan properties accounting for about 130 wells of an estimated 240 to 280 well program. With our existing production declining at an annual rate of about 20% (or 12,800 BOE/d per year on an estimated initial production base of 64,000 BOE/d), our 2006 capital program will target a success rate of $20,000 per flowing BOE/d. We anticipate that with our planned capital program, production for 2006 will be approximately 60,000 BOE/d.

Beyond 2006, Harvest currently anticipates that our production will continue to be 75% oil weighted, consistently with our 2006 capital spending plans. With our 2006 natural gas production estimated to be approximately 100,000 mcf/d (16,000 BOE/d) following the merger with Viking, our Cash Flows in 2006 will continue to be more sensitive to changes in the benchmark price for crude oil (WTI) and to a lesser extent, the heavy oil price differentials in western Canada than to changes in natural gas prices, although our natural gas prices are relatively unprotected. At the end of 2005, we had oil price risk management contracts in place in respect of approximately 25,000 bbl/d for 2006 and 17,500 bbl/d in 2007. The 2006 contracts provide downside protection should the WTI benchmark price drop below US$46.00. This protection is exchanged for reduced participation in upward price movement that exceeds US$46.00 on approximately 53% of expected oil production (67% of our expected production after deduction of the various royalty interests), while our 2007 contracts provide downside protection at US$55.00 with a reduced participation in prices that exceed US$55.00. At the end of 2005, our 2006 oil price risk management contracts had a mark-to-market deficiency of $66.0 million while the 2007 contracts had a deficiency of $10.4 million. The following chart reflects the weighted average price Harvest will receive for the approximately 25,000 bbl/d of oil price contracted for 2006 at various WTI oil prices:

In addition to our WTI price contracts, we have entered into heavy oil price differential contracts that fix the price differential at approximately 29% of the WTI benchmark price on 10,000 bbl/d in 2006. This represents approximately 55% of our expected heavy oil production for 2006, after adjusting for volumes added during blending. At the end of 2005, these contracts had a mark-to-market value of $14.1 million.

We anticipate that our 2006 operating costs will average approximately $10.00 per BOE, reflecting the industry wide cost pressures of 10% to 15%, offset by our fixed price power purchase contracts. For 2006, we have entered into fixed price power purchase contracts for approximately 45 MWh at an average cost of approximately $50.00 per MWh representing approximately 79% of our anticipated power purchase requirements. Compared to our 2005 operating cost of $9.07/BOE ($9.54 excluding adjustments for the benefits of the fixed price power purchase contracts) our per BOE operating cost expectation for 2006 of approximately $10.00 is within industry expectations. For 2006, we anticipate our general and administrative costs will average about $1.25 per BOE before the charges for unit based compensation expense and the one time charges relating to our Arrangement with Viking.

We have declared per Trust Unit distributions of $0.35 for January 2006 and $0.38 for February and March 2006, and provided commodity prices remain between US$55 to US$60 for the WTI benchmark oil price and $7 and $9 for the AECO benchmark price for Alberta natural gas, it is anticipated that distributions of $0.38 per trust unit for the balance of 2006 would reflect a payout ratio of approximately 70%. With anticipated 2006 capital spending of $250 million and monthly distributions of $0.38 per Trust Unit for the balance of the year, Cash Flows after distributions would be approximately $50 million short to fund the expected 2006 capital spending before considering the reinvestment of distributions by Unitholders. A participation level of approximately 25% by our Unitholders in our distribution reinvestment programs would be required to offset the shortfall compared to our current participation level of 40%.

The following table reflects sensitivities of Harvest's anticipated 2006 Cash Flow to key assumptions in our ongoing business.

		Assumption		Change	Impact on Cash Flow
WTI oil price ($US/bbl)	$	58.00	$	5.00	$	0.55 / Unit
CAD/USD exchange rate	$	0.87	$	0.02	$	0.12 / Unit
AECO daily natural gas price	$	10.00	$	2.00	$	0.45 / Unit
Interest rate on outstanding bank debt		5.00%		1.0%	$	0.01 / Unit
Liquids production volume (bbl/d)		44,500		2,000	$	0.35 / Unit
Natural gas production volume (mcf/d)		92,000		5,000	$	0.14 / Unit
Operating Expenses (per BOE)	$	10.00	$	1.00	$	0.21 / Unit

Summary of Historical Annual Results

		Years ended December 31
($ 000s except Trust Unit and per Trust Unit amounts)		2005		2004		2003
				(restated)		(restated)
Revenue, net of royalties		554,494		275,819		102,939
Cash flows⁽¹⁾		309,843		123,710		46,492
Per Trust Unit, basic⁽¹⁾	$	6.66	$	4.94	$	3.69
Per Trust Unit, fully diluted⁽¹⁾	$	6.35	$	3.97	$	3.58
Net income		104,946		11,241		14,646
Per Trust Unit, basic	$	2.25	$	0.45	$	1.16
Per Trust Unit, fully diluted	$	2.19	$	0.43	$	1.13
Total assets		1,308,481		1,050,483		256,440
Total long-term financial liabilities		349,074		326,250		25,000

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

Summary of Fourth Quarter Results

FINANCIAL	Three months ended December 31
	2005	2004	Change
Revenues	185,824	128,907	44%
Royalties	(31,178)	(21,944)	42%
Realized losses on risk management contracts⁽³⁾	(8,726)	(16,116)	46%
Unrealized gains on risk management contracts	28,463	18,122	57%
Net revenues	174,383	108,969	60%

Operating expenses	38,834	25,725	51%
Realized gains on power hedge	(4,507)	(611)	638%
Net operating expenses	34,327	25,114	37%

General and administrative expenses	5,651	13,447	58%
Less: Unit based compensation expenses	(1,568)	(10,590)	85%
Total cash general and administrative expenses	4,083	2,857	43%

Interest expense	8,499	9,919	14%
Net income	75,638	11,600	552%
Payout ratio	57%	47%	10%
Capital asset additions (excluding acquisitions)	39,476	8,873	345%

OPERATING
Daily sales volumes
Light / medium oil (bbl/d)	20,471	16,004	28%
Heavy oil (bbl/d)	13,273	15,121	(12%)
Natural gas liquids (bbl/d)	867	1,310	(34%)
Natural gas (mcf/d)	25,339	28,678	12%)
	38,834	37,215	4%

OPERATING NETBACKS⁽¹⁾ ($/BOE)
Revenue	52.01	37.65	38%
Realized loss on risk management contracts	(3.70)	(4.89)	(24%)
Royalties as a percent of revenue	(8.73)	(6.41)	36%
As a percent of revenue	16.8%	17.0%	-
Operating expense⁽²⁾	(9.60)	(7.34)	31%
Operating Netback⁽¹⁾	29.98	19.01	58%

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

(2) Includes realized gain on electricity risk management contract of $1.26/BOE and $0.18/BOE for the three months ended December 31, 2005 and 2004 respectively.

⁽³⁾ Includes gains on electricity risk management contracts of $4.5 million and $2.6 million for the three months ended December 31, 2005 and 2004.

Our 2005 fourth quarter revenues have increased over the fourth quarter in 2004 as a result of higher commodity prices and a change in product mix due to the acquisition of the Hay River property. Light / medium oil sales revenue for the three month period ended December 31, 2005 was $37.5 million (or 52%) higher than in same period in the prior year due to a favourable price variance of $17.7 million and a favourable volume variance of $19.8 million. Heavy oil revenues for the three months ended December 31, 2005 increased by $7.3 million (or 19%) due to a favourable price variance of $11.9 million and an unfavourable volume variance of $4.6 million. Natural gas sales revenue increased by $11.5 million (or 76%) for the three months ended December 31, 2005 over the same period in 2004, which reflects a favourable price variance of $13.2 million and an unfavourable volume variance of $1.7 million. The decrease in natural gas volumes in the fourth quarter of 2005 compared to the fourth quarter of 2004 reflects the natural declines in our natural gas properties.

Our fourth quarter 2005 production volumes are higher than in 2004 due to the impact of the Hay River acquisition made in the third quarter of 2005. Production in the fourth quarter of 2005 reflects a full quarter of production from Hay River as well as added production from our drilling activity in the year.

For the three months ended December 31, 2005, our net royalties as a percentage of revenue were 16.8% ($31.2 million), compared to 17.0% ($21.9 million) in the same period in 2004. The small decrease in the royalty rate in the fourth quarter of 2005 compared with the same period in 2004, considering the 37% increase in net prices and higher royalty rates for the Hay River property, is attributable to higher than expected Alberta Royalty Tax Credits recognized in the fourth quarter for drilling activity in the province during the year.

Operating expenses increased by $13.1 million (or 51%) for the three months ended December 31, 2005 compared to the same period in the prior year. The increase in fourth quarter costs in 2005 relative to 2004 reflects inflationary cost pressures in the Western Canadian oil and natural gas sector and power costs.

For the three months ended December 31, 2005, Cash G&A increased by $1.2 million (or 43%) compared to the same period in the prior year. This increase is reflective of additional staffing costs relating to the Hay River acquisition, business development costs and generally higher costs for our external service providers.

For the three months ended December 31, 2005, interest expense decreased by $1.4 million relative to the same period in the prior year due to lower average debt balances on the credit facility in 2005.

Summary of Historical Quarterly Results

The table and discussion below highlight our performance for the previous eight quarters on select measures. Our Initial Public Offering took place in December of 2002.

									(Restated-Refer to Note 3 of consolidated financial statements)
				2005								2004
Financial		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Revenue, net of royalties	$	154,646	$	169,654	$	120,263	$	109,931	$	106,964	$	85,096	$	44,461	$	39,298

Net income (loss)		75,638		52,862		19,516		(43,070)		11,600		1,740		151		(2,250)
Per Trust Unit, basic²		1.45		1.09		0.45		(1.02)		0.29		0.06		0.01		(0.13)
Per Trust Unit, diluted²		1.42		1.08		0.44		(1.02)		0.27		0.06		0.01		(0.13)
Cash Flows¹		96,431		103,508		52,217		52,687		52,870		41,267		15,839		13,734
Per Trust Unit, basic¹		1.84		2.14		1.32		1.25		1.31		1.42		0.91		0.80
Per Trust Unit, diluted¹		1.81		2.09		1.29		1.19		1.18		1.12		0.78		0.67

Distributions per Unit,
declared		1.05		0.95		0.60		0.60		0.60		0.60		0.60		0.60
Total long term financial
liabilities		349,074		386,124		455,163		321,534		326,250		95,609		57,780		58,984
Total assets		1,308,481		1,327,272		1,117,792		1,079,269		1,050,459	1,070,016			488,204		260,658
Total production (BOE/d)		38,834		37,549		34,463		35,386		37,215		24,856		15,233		15,070

(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.

The above table highlights our performance over the fourth quarter of 2005, and the preceding seven quarters.

Net revenues and Cash Flows have increased steadily over the eight quarters shown as above. The significantly higher revenue and Cash Flows in the third quarter of 2005 relative to the second quarter of 2005 is primarily due to higher production from the Hay River acquisition, stronger crude oil prices and narrower heavy oil differentials early in the quarter. This trend did not continue into the fourth quarter of 2005 as a result of decreased commodity prices and widening heavy oil differentials. The most significant increases in revenue occurred through the second and third quarter of 2005, due to unprecedented commodity prices, and the third and fourth quarters of 2004, as a result of the two acquisitions completed in June and September of that year. The general increasing revenue trend since the fourth quarter of 2003 is also attributable to the strong commodity price environment through 2004 and 2005. 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 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 accounted for increased volatility in our 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. Production increases in the latter half of 2005, despite natural declines reflect the addition of the Hay River property as well as added production from our drilling program.

Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure that information required to be disclosed is accumulated and communicated to our management as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have concluded, based on their evaluation as of the end of the period covered by the annual filings, that our disclosure controls and procedures as of the end of such period are effective to provide reasonable assurance that material information relating to the Trust and its consolidated subsidiaries, is made known to them by others within those entities. It should be noted that while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control system are met.

Critical Accounting Policies

Oil and Natural Gas Accounting

In accounting for oil and natural gas activities, we can choose to account for our oil and natural gas activities using either the full cost or the successful efforts method of accounting.

We follow the Canadian Institute of Chartered Accountants guideline 16, "Oil and Gas Accounting – Full Cost" for the full cost method of accounting for our oil and natural gas activities. All costs of acquiring oil and natural gas properties and related exploration and development costs, including overhead charges directly related to these activities, are capitalized and accumulated in one cost centre. Maintenance and repairs are charged against income, and renewals and enhancements that extend the economic life of the capital assets are capitalized. Any gains or losses on disposition of oil and natural gas properties are not recognized unless that disposition would alter the rate of depletion by 20% or more. The provision for depletion and depreciation of petroleum and natural gas assets is calculated on the unit-of-production method, based on proved reserves before royalties as estimated by independent petroleum engineers. The basis used for the calculation of the provision is the capitalized costs of petroleum and natural gas assets plus the estimated future development costs of proved undeveloped reserves. Reserves are converted to equivalent units on the basis of six thousand cubic feet of natural gas to one barrel of oil. The reserve estimates used in these calculations can have a significant impact on net income, and any downward revision in this estimate could result in a higher depletion and depreciation expense. In addition, a downward revision of this reserve estimate could require an additional charge to income as a result of the computation of the prescribed ceiling test under this guideline. Under this method of accounting, an impairment test is applied to the overall carrying value of the capital assets for a Canada-wide cost centre with reserves valued at estimated future commodity prices at period end.

Under the successful efforts method of accounting, all exploration costs, except costs associated with drilling successful exploration wells, are expensed in the period in which they are incurred and costs are generated on a property by property basis. Impairment is also determined on a property by property basis.

The difference between these two approaches is not expected to produce significantly different results for us, as our success rates for drilling activities are high. However, each policy is likely to generate a different carrying value of capital assets and different net income.

Critical Accounting Estimates

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

Reserves

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

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

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

The estimates in reserves impact many of our accounting estimates including our depletion calculation. A decrease of reserves by 10% would result in an increase of approximately $18 million in our depletion expense.

Asset Retirement Obligations

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

Impairment of Capital Assets

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

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

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

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

Any impairment charges would reduce our net income.

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

Impact on Net Income of Change in Accounting Policies

The implementation of new accounting policies in 2005 as discussed below resulted in changes to the accounting treatment for exchangeable shares, convertible debentures and the equity bridge notes. As a result, we have restated previously reported annual and quarterly net income. The restatements were required per the transitional provisions of the respective accounting standards. The following table illustrates the impact of the new accounting policies on quarterly net income (loss) and net income (loss) per Unit for periods which have been presented for comparative purposes:

	2004
$ thousands)	Q4	Q3	Q2	Q1
Net Income (loss) before change in accounting policies¹	12,536	5,166	1,594	(1,065)
Decrease in net income
Interest expense²	(751)	(3,386)	(1,443)	(1,185)
Non-controlling interest³	(185)	(40)	-	-
Net income (loss) after change in accounting policies	11,600	1,740	151	(2,250)

Net income (loss) per Trust Unit, as reported
Basic	0.29	0.07	0.02	(0.06)
Diluted	0.28	0.07	0.02	(0.06)

Net income (loss) per Trust Unit, as restated
Basic	0.29	0.06	0.01	(0.13)
Diluted	0.27	0.06	0.01	(0.13)

Note 1 This represents net income as reported before retroactive restatement for changes in accounting policies.

Note 2 Adoption of the amendment to CICA Handbook Section 3860 "Financial Instruments – Disclosure and Presentation" resulted in the convertible debentures and equity bridge notes being classified as debt whereas previously they were classified as equity. In addition, the interest expense relating to these instruments was required to be charged against net income rather than directly to accumulated income. Also, the deferred financing charges associated with the convertible debentures are now reflected separately in deferred charges on the balance sheet and amortized to income over the term of the debt; previously they were applied as a reduction to the outstanding balance.

Note 3 Adoption of EIC 151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", resulted in the exchangeable shares being classified as minority interest and the income attributed to minority interest holders being applied against net income.

Changes in Accounting Policy

Financial Instruments

On January 1, 2005, the Trust retroactively adopted the amendment to the Canadian Institute of Chartered Accountants ("CICA") handbook section 3860 "Financial Instruments". These changes require that fixed-amount contractual obligations that can be settled by issuing a variable number of equity instruments be classified as liabilities. The convertible debentures and the equity bridge notes previously issued by the Trust have characteristics that meet the noted criteria and we have retroactively accounted for these instruments as debt and reflected related interest costs as interest expense in the statement of income.

Exchangeable Shares

On January 19, 2005, the CICA issued EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts" that states that equity interests held by third parties in subsidiaries of an income trust should be reflected as either non-controlling interest or debt in the consolidated balance sheet unless they meet certain criteria. EIC-151 requires that the shares be nontransferable in order to be classified as equity. The exchangeable shares issued by Harvest Operations are transferable and, in accordance with EIC-151, have been reclassified to non-controlling interest on the consolidated balance sheet. In addition, a portion of consolidated income or loss before non-controlling interest is reflected as a reduction to such income or loss in the Trust's consolidated statement of income. Prior periods have been retroactively restated.

Variable Interest Entities ("VIEs")

In June 2003, the CICA issued Accounting Guideline 15 "Consolidation of Variable Interest Entities" ("AcG-15"). AcG-15 defines VIEs as entities in which either: the equity at risk is not sufficient to permit that entity to finance its activities without additional financial support from other parties; or equity investors lack voting control, an obligation to absorb expected losses or the right to receive expected residual returns. AcG-15 harmonizes Canadian and U.S. GAAP and provides guidance for companies consolidating VIEs in which it is the primary beneficiary. The guideline is effective for all annual and interim periods beginning on or after November 1, 2004. We have performed a review of entities in which the Trust has an interest and have determined that we do not have any variable interest entities at this time.

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.

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 is permitted as of the beginning of a period beginning on or after July 1, 2005. We do not expect the adoption of this section will have a material impact on our results of operations or financial position.

Operational and Other Business Risks

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

Operation of oil and natural gas properties:

Applying a proactive management approach to our properties;

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

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

Estimates of the quantity of recoverable reserves:

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

Commodity price exposures:

Maintaining a risk-management policy and committee to continuously review effectiveness of existing actions, identify new or developing issues and devise and recommend to the Board of Directors of Harvest Operations action to be taken;

Executing risk management contracts with a portfolio of credit-worthy counterparties; and

Maintaining a low cost structure to maximize product netbacks.

Financial risk:

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

Environmental, health and safety risks:

Adhering to our safety program and keeping abreast of current industry practices; and

Committing funds on an ongoing basis, toward the remediation of potential environmental issues.

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

Retaining an experienced, diverse and actively involved Board of Directors to ensure good corporate governance; and

Engaging technical specialists when necessary to advise and assist with the implementation of policies and procedures to assist in dealing with the changing regulatory environment.

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 Flows as cash flow from operating activities before changes in non-cash working capital and settlement of asset retirement obligations. Cash Flows 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 Flows 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 Flows. 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 twelve months ended December 31, 2005 and 2004, Cash Flows are reconciled to its closest GAAP measure, Cash Flows from operating activities, as follows:

	Three Months ended December 31				Years ended December 31
$000		2005		2004		2005		2004

Cash Flows	$	96,431	$	52,870	$	309,843	$	123,710
Settlement of asset retirement obligations		(1,813)		(622)		(4,146)		(929)
Changes in non-cash working capital		3,348		(230)		(22,519)		(11,103)
Cash flow from operating activities	$	97,966	$	52,018	$	283,178	$	111,678

Forward-Looking Information

This MD&A highlights significant business results and statistics from our consolidated financial statements for the year ended December 31, 2005 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. Forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

Additional Information

Further information about us, including our Annual Information Form, can be accessed under our public filings found on SEDAR at www.sedar.com or at www.harvestenergy.ca. Information can also be found by contacting our Investor Relations department at (403)268-1178 or at 1-866-666-1178.

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Readability	7th grade Avg

Harvest Energy Trust (HTE) Inactive 40-F2005 FY Annual report (Canada)

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