Harvest Operations 6-K Report of Foreign Private Issuer

 

  MANAGEMENT’S DISCUSSION AND ANALYSIS

MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with the unaudited interim consolidated financial statements of Harvest Operations Corp. (“Harvest”, “we”, “us”, “our” or the “Company”) for the three and six months ended June 30, 2012 and the audited consolidated financial statements and MD&A for the year ended December 31, 2011. The information and opinions concerning our future outlook are based on information available at August 8, 2012.

In this MD&A, all dollar amounts are expressed in Canadian dollars unless otherwise indicated. Tabular amounts are in thousands of dollars, except where noted. Natural gas volumes are converted to barrels of oil equivalent (“boe”) using the ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel of oil (“bbl”). Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf to 1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. In accordance with Canadian practice, petroleum and natural gas revenues are reported on a gross basis before deduction of Crown and other royalties. In addition to disclosing reserves under the requirements of National Instrument (“NI”) 51-101, Harvest also discloses our reserves on a company interest basis which is not a term defined under NI 51-101. This information may not be comparable to similar measures by other issuers.

Additional information concerning Harvest, including its Annual Information Form (“AIF”) can be found on SEDAR atwww.sedar.com.

ADVISORY

This MD&A contains non-GAAP measures and forward-looking information about our current expectations, estimates and projections. Readers are cautioned that the MD&A should be read in conjunction with the “Non-GAAP Measures” and “Forward-Looking Information” sections at the end of this MD&A.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

SELECTED INFORMATION
The table below provides a summary of Harvest’s financial and operating results for the three and six months ended June 30, 2012 and 2011.

	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011
FINANCIAL
Revenues(1)	1,533,808		782,041		2,959,948		2,030,964
Cash from operating activities	70,850		107,588		155,960		254,364
Net income (loss)	(73,293	)	(19,529	)	(145,374	)	18,435
Bank loan	640,249		171,914		640,249		171,914
Convertible debentures	740,393		743,701		740,393		743,701
Senior notes	497,044		469,247		497,044		469,247
Total financial debt(2)	1,877,686		1,384,862		1,877,686		1,384,862
Total assets	6,277,496		6,121,547		6,277,496		6,121,547
UPSTREAM OPERATIONS
Daily sales volumes (boe/d)	60,874		55,338		60,712		54,340
Average realized price
Oil and NGLs ($/bbl)(3)	70.83		85.01		75.07		79.31
Gas ($/mcf)	2.11		4.12		2.20		3.99
Operating netback prior to hedging ($/boe)(2)	27.47		36.94		28.34		35.34
Operating income (loss)	(17,704	)	26,730		(37,469	)	49,950
Cash contribution from operations(2)	140,950		158,525		288,022		305,814
Capital asset additions (excluding acquisitions)	124,635		125,501		363,227		363,150
Property and business acquisitions (dispositions), net	1,235		411		(753	)	515,908
Decommissioning and environmental remediation expenditures	3,373		4,282		9,960		6,249
Net wells drilled	20.9		14.4		81.3		119.3
Net undeveloped land additions (acres)(4)	10,156		54,560		55,087		331,445
DOWNSTREAM OPERATIONS
Average daily throughput (bbl/d)	114,552		38,016		107,276		67,563
Average refining margin (US$/bbl)	2.71		8.09		3.58		10.21
Operating income (loss)	(42,529	)	(31,681	)	(91,404	)	4,563
Cash contribution (deficiency) from operations(2)	(15,022	)	(9,571	)	(38,811	)	46,329
Capital asset additions	6,538		108,741		19,801		144,620

(1)	Revenues are net of royalties and the effective portion of Harvest’s realized crude oil hedges.
(2)	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.
(3)	Excludes the effect of risk management contracts designated as hedges.
(4)	Includes lands acquired in business combinations.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

REVIEW OF OVERALL PERFORMANCE

Upstream

• Sales volumes increased 5,536 boe/d to 60,874 boe/d from the second quarter of 2011 primarily due to the Plains Rainbow Pipeline outage in 2011 and the results of our capital drilling program.

• Operating netback was $27.47/boe prior to hedging for the second quarter of 2012, a decrease of 26% from the same quarter in 2011, reflecting lower realized prices for all commodities, partially offset by lower royalties and transportation costs.

• Operating loss was $17.7 million for the second quarter of 2012 as compared to operating income of $26.7 million for the same quarter in 2011. The decrease in operating income is mainly attributable to the lower operating netback, increased depreciation, depletion and amortization, and increased exploration and evaluation costs.

• Cash contribution from operations was $141.0 million for the second quarter of 2012, a $17.6 million decrease from the same quarter in the prior year which was driven by the lower operating netback.

• Capital spending of $124.6 million includes the drilling of 9 gross conventional wells and 14 gross SAGD wells.

Downstream

• Throughput volume averaged 114,552 bbl/d, an increase of 201% as compared to a throughput volume of 38,016 bbl/d in the second quarter of 2011 due to the planned turnaround maintenance that occurred in 2011.

• Refining gross margin averaged $2.71/bbl in the second quarter of 2012, a decrease of $5.38/bbl from the same quarter in 2011 mainly due to lower product crack spreads as a result of a decreased sour crude differential, declining product prices and higher vacuum gas oil costs.

• Operating loss totaled $42.5 million for the three months ended June 30, 2012 as compared to an operating loss of $31.7 million in the same period in 2011. The increase in operating loss reflects the decrease in gross margin/bbl which was offset by increased throughput volume, as well as increases in operating expense and purchased energy expense.

• Cash deficiency from operations was $15.0 million for the second quarter of 2012, a $5.5 million greater deficiency than the same quarter in the prior year mainly due to higher operating expenses.

• Capital spending was $6.5 million for the quarter of which $0.8 million was spent on the debottlenecking project.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

UPSTREAM OPERATIONS

Summary of Financial and Operating Results

	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011
FINANCIAL
Petroleum and natural gas sales(1)	292,377		323,456		616,528		604,506
Royalties	(38,790	)	(56,561	)	(92,207	)	(92,419	)
Revenues	253,587		266,895		524,321		512,087
Expenses
Operating	88,536		82,315		188,511		165,910
Transportation and marketing	5,381		11,126		11,067		14,129
Realized (gains) losses on risk management contracts(2)	174		16		174		(2,208	)
Operating netback after hedging(3)	159,496		173,438		324,569		334,256
General and administrative	17,962		14,817		30,115		28,339
Depreciation, depletion and amortization	147,059		127,934		291,542		249,278
Exploration and evaluation	12,348		4,243		19,084		10,454
Impairment of property, plant and equipment	-		-		21,843		-
Unrealized (gains) losses on risk management contracts(4)	194		154		(77	)	(3,085	)
Gains on disposition of property, plant and equipment	(363	)	(440	)	(469	)	(680	)
Operating income (loss)	(17,704	)	26,730		(37,469	)	49,950
Capital asset additions (excluding acquisitions)	124,635		125,501		363,227		363,150
Property and business acquisitions (dispositions), net	1,235		411		(753	)	515,908
Abandonment and reclamation expenditures	3,373		4,282		9,960		6,249
OPERATING
Light / medium oil (bbl/d)	25,617		22,294		25,276		23,900
Heavy oil (bbl/d)	8,842		8,559		9,057		8,797
Natural gas liquids (bbl/d)	5,469		5,937		5,568		4,703
Natural gas (mcf/d)	125,680		111,291		124,863		101,643
Total (boe/d)	60,874		55,338		60,712		54,340

(1) Including the effective portion of Harvest’s realized crude oil hedges.
(2) Realized (gains) losses on risk management contracts include the settlement amounts for power derivative contracts and the ineffective portion of realized crude oil hedges.
(3) This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.
(4) Unrealized (gains) losses on risk management contracts reflect the change in fair value of the power derivative contracts and the ineffective portion of crude oil hedges.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Commodity Price Environment

	Three Months Ended June 30				Six Months Ended June 30
	2012	2011	Change		2012	2011	Change
West Texas Intermediate (“WTI”) crude oil (US$/bbl)	93.49	102.56	(9%	)	98.21	98.33	-
West Texas Intermediate (“WTI”) crude oil ($/bbl)	94.32	99.22	(5%	)	98.67	95.98	3%
Edmonton light sweet crude oil ($/bbl)	83.98	103.26	(19%	)	88.18	95.65	(8%	)
Western Canadian Select (“WCS”) crude oil ($/bbl)	71.29	82.09	(13%	)	76.45	76.14	-
AECO natural gas daily ($/mcf)	1.91	3.88	(51%	)	2.03	3.82	(47%	)
U.S. / Canadian dollar exchange rate	0.990	1.033	(4%	)	0.995	1.024	(3%	)
Differential Benchmarks
WCS differential to WTI ($/bbl)	23.03	17.13	34%		22.22	19.84	12%
WCS differential as a % of WTI	24.4%	17.3%	41%		22.5%	20.7%	9%

The average WTI benchmark price in the second quarter of 2012 was 9% lower than the second quarter of 2011, but is even at US$98/bbl for the six months ended June 30, 2012. The average Edmonton light sweet crude oil price (“Edmonton Light”) decreased in the second quarter of 2012 compared to the second quarter of 2011, due to the lower WTI price and the widening of the light sweet differential. For the six months ended June 30, 2012, the Edmonton light price decreased as compared to the same period in 2011 due to the widening of the light sweet differential.

Heavy oil differentials fluctuate based on a combination of factors including the level of heavy oil inventories, pipeline capacity to deliver heavy crude to U.S. markets and the seasonal demand for heavy oil. For the three months ended June 30, 2012, the WCS price decreased 13% from the same period in 2011, which is consistent with the lower WTI price and the widening of the WCS differential relative to WTI.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Realized Commodity Prices

	Three Months Ended				Six Months Ended
	June 30				June 30
	2012	2011	Change		2012	2011	Change
Light to medium oil prior to hedging ($/bbl)	76.18	94.08	(19%	)	80.46	85.91	(6%	)
Heavy oil ($/bbl)	64.02	74.84	(14%	)	69.28	68.03	2%
Natural gas liquids ($/bbl)	56.76	65.60	(13%	)	60.04	66.86	(10%	)
Natural gas ($/mcf)	2.11	4.12	(49%	)	2.20	3.99	(45%	)
Average realized price prior to hedging ($/boe)(1)	51.42	66.73	(23%	)	54.74	63.05	(13%	)
Light to medium oil after hedging ($/bbl)(2)	79.41	87.87	(10%	)	83.00	82.29	1%
Average realized price after hedging ($boe)(1)(2)	52.78	64.23	(18%	)	55.80	61.46	(9%	)

(1)	Inclusive of sulphur revenue.
(2)	Inclusive of the realized gains (losses) from contracts designated as hedges. Contracts that are not designated as hedges are excluded from the realized price.

Prior to hedging activities, our realized price for light to medium oil for the three and six months ended June 30, 2012 decreased by 19% and 6%, respectively, compared to the same periods in 2011. This decrease is consistent with the downward movement in Edmonton Light prices during the first three and six months of 2012.

In order to mitigate the risk of fluctuating cash flows due to crude oil price volatility, Harvest has entered into fixed-for-floating swaps. The impact of this hedging activity resulted in an increase of $3.23/bbl (2011 – decrease of $6.21/bbl) in Harvest’s realized light to medium oil price for the three months ended June 30, 2012 and an increase of $2.54/bbl (2011 – decrease of $3.62/bbl) for the six months ended June 30, 2012. With respect to our cash flow risk management program, see “Cash Flow Risk Management” in this MD&A.

Harvest’s realized heavy oil prices for the three months ended June 30, 2012 decreased by 14% compared to the same period in 2011, mainly due to the decrease in the WCS benchmark. Harvest’s realized heavy oil prices for the six months ended June 30, 2012 increased by 2% compared to the same period in 2011, which is comparable to the modest increase of the WCS benchmark.

The realized prices for NGLs decreased 13% and 10% for the three months and six months ended June 30, 2012 mainly due to decreases in market prices.

The average realized price for Harvest’s natural gas sales decreased by 49% for the three months ended June 30, 2012 and 45% for the six months ended June 30, 2012 as compared to the same periods in 2011, reflecting the decrease in the AECO benchmark price.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Sales Volumes

	Three Months Ended June 30
	2012		2011
	Volume	Weighting	Volume	Weighting	% Volume
					Change
Light to medium oil (bbl/d)(1)	25,617	42%	22,294	40%	15%
Heavy oil (bbl/d)	8,842	15%	8,559	15%	3%
Natural gas liquids (bbl/d)	5,469	9%	5,937	11%	(8%	)
Total liquids (bbl/d)	39,928	66%	36,790	66%	9%
Natural gas (mcf/d)	125,680	34%	111,291	34%	13%
Total oil equivalent (boe/d)	60,874	100%	55,338	100%	10%

	Six Months Ended June 30
	2012		2011
	Volume	Weighting	Volume	Weighting	% Volume
					Change
Light to medium oil (bbl/d)(1)	25,276	42%	23,900	44%	6%
Heavy oil (bbl/d)	9,057	15%	8,797	16%	3%
Natural gas liquids (bbl/d)	5,568	9%	4,703	9%	18%
Total liquids (bbl/d)	39,901	66%	37,400	69%	7%
Natural gas (mcf/d)	124,863	34%	101,643	31%	23%
Total oil equivalent (boe/d)	60,712	100%	54,340	100%	12%

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

Harvest’s sales volumes were 60,874 boe/d for the second quarter of 2012 and 60,712 boe/d for the first six months of 2012, an increase of 10% and 12% respectively, as compared to the same periods in 2011. The increase in the second quarter reflects the impact of the Plains Rainbow Pipeline outage in the prior year and the results of our capital drilling program. The increase in the first six months of 2012 reflects the full period benefit of the assets acquired from Hunt at the end of February 2011 as well as production increases resulting from Harvest’s capital program.

8

 

  MANAGEMENT’S DISCUSSION AND ANALYSIS

Harvest’s average light/medium oil sales were 25,617 bbl/d and 25,276 bbl/d for the three and six months ended June 30, 2012, a 15% and 6% increase, respectively, from the same periods in 2011. The increases from 2011 are mainly due to the Plains Rainbow Pipeline outage and production disruptions associated with flooding in the SE Saskatchewan area that occurred in the prior year.

Heavy oil sales for both the three months and six months ended June 30, 2012 increased by 3%, as compared to the same periods in 2011, reflecting production increases from Harvest’s 2011 drilling and reactivation programs.

 

Natural gas sales increased 13% in the second quarter of 2012 compared to the second quarter of 2011 mainly due to the results of the 2011 drilling in Willesden Green and Deep Basin, combined with production shut-in during the second quarter of 2011 to redirect the wells in the Crossfield area to another gas plant. The increased production in the second quarter of 2012, together with the full period production from the assets acquired from Hunt in 2011, contribute to the 23% volume increase in the first six months of 2012, as compared to the same period in 2011.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Natural gas liquids sales for the second quarter 2012 decreased by 8% compared to the same period in 2011, mainly as a result of an ongoing gas plant turnaround in the Caroline area in the second quarter of 2012. Sales for the first six months of 2012 increased by 18% mainly due to the full period production from the assets acquired from Hunt at the end of February 2011.

Revenues

	Three Months Ended June 30						Six Months Ended June 30
	2012		2011		Change		2012		2011		Change
Light / medium oil sales after hedging(1)	185,107		178,265		4%		381,834		355,991		7%
Heavy oil sales	51,508		58,293		(12%	)	114,198		108,325		5%
Natural gas sales	24,171		41,704		(42%	)	50,048		73,383		(32%	)
Natural gas liquids sales	28,249		35,439		(20%	)	60,844		56,912		7%
Other(2)	3,342		9,755		(66%	)	9,604		9,895		(3%	)
Petroleum and natural gas sales	292,377		323,456		(10%	)	616,528		604,506		2%
Royalties	(38,790	)	(56,561	)	(31%	)	(92,207	)	(92,419	)	-
Revenues	253,587		266,895		(5%	)	524,321		512,087		2%

(1)	Including the effective portion of realized gains (losses) from crude oil contracts designated as hedges.
(2)	Including sulphur revenue and miscellaneous income.

Harvest’s revenue is subject to changes in sales volumes, commodity prices and currency exchange rates. In the second quarter of 2012, total petroleum and natural gas sales decreased by $31.1 million, mainly due to the 18% decrease in realized prices after hedging activities, partially offset by the 10% increase in sales volumes. For the first six months of 2012, total petroleum and natural gas sales increased by $12.0 million, mainly due to the 12% increase in sales volumes, partially offset by the 9% decrease in realized prices after hedging activities. Sulphur revenue represented $3.3 million (2011 - $7.7 million) of the total in other revenues for the second quarter of 2012 and $9.4 million (2011 - $7.8 million) for the first six months of 2012, with the decrease in the second quarter of 2012 mainly resulting from the Caroline plant turnaround.

Royalties
Harvest pays 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 various sliding scales dependent on incentives, production volumes and commodity prices.

For the second quarter of 2012, royalties as a percentage of gross revenue averaged 13.3% (2011 – 17.5%) . The lower royalty rate is mainly due to the annual Alberta Crown gas cost allowance adjustment. For the six months ended June 30, 2012, royalties as a percentage of gross revenue averaged 15.0% (2011 – 15.3%), comparable to the same period in 2011.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Operating and Transportation Expenses

	Three Months Ended June 30
					$/boe
	2012	$/boe	2011	$/boe	Change
Power and purchased energy	16,761	3.03	16,599	3.30	(0.27	)
Well servicing	15,195	2.74	16,276	3.23	(0.49	)
Repairs and maintenance	16,021	2.89	13,578	2.70	0.19
Lease rentals and property tax	9,010	1.63	7,977	1.58	0.05
Labor - internal	7,567	1.37	6,695	1.33	0.04
Labor - contract	4,573	0.83	5,047	1.00	(0.17	)
Chemicals	4,559	0.82	4,147	0.82	-
Trucking	4,121	0.74	3,402	0.68	0.06
Processing and other fees	8,545	1.54	4,819	0.96	0.58
Other	2,184	0.39	3,775	0.75	(0.36	)
Total operating expenses	88,536	15.98	82,315	16.35	(0.37	)
Transportation and marketing	5,381	0.97	11,126	2.21	(1.24	)

	Six Months Ended June 30
					$/boe
	2012	$/boe	2011	$/boe	Change
Power and purchased energy	37,261	3.37	38,150	3.88	(0.51	)
Well servicing	33,715	3.05	33,189	3.37	(0.32	)
Repairs and maintenance	32,185	2.91	26,449	2.69	0.22
Lease rentals and property tax	18,530	1.68	15,745	1.60	0.08
Labor - internal	16,757	1.52	13,743	1.40	0.12
Labor - contract	9,891	0.90	9,120	0.93	(0.03	)
Chemicals	9,143	0.83	7,973	0.81	0.02
Trucking	8,676	0.78	5,956	0.61	0.17
Processing and other fees	17,238	1.56	6,126	0.62	0.94
Other	5,115	0.46	9,459	0.96	(0.50	)
Total operating expenses	188,511	17.06	165,910	16.87	0.19
Transportation and marketing	11,067	1.00	14,129	1.44	(0.44	)

Operating costs for the second quarter of 2012 totaled $88.5 million, an increase of $6.2 million compared to the same period in 2011, mainly attributable to the increase in volumes produced. Operating costs on a per barrel basis have decreased by 2% to $15.98/boe mainly due to the lower cost of Alberta electricity.

On a year-to-date basis, operating costs for 2012 totaled $188.5 million, an increase of $22.6 million when compared to the same period in 2011 mainly due to increased production. On a per barrel basis, year-to-date operating costs increased by $0.19/boe which is mainly attributable to higher processing and other fees, partially offset by lower power and purchased energy costs.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Three Months Ended					Six Months Ended
	June 30					June 30
($ per boe)	2012	2011		Change		2012	2011		Change
Power and purchased energy costs	3.03	3.30		(0.27	)	3.37	3.88		(0.51	)
Realized gains on electricity risk    management contracts	-	(0.07	)	0.07		-	(0.27	)	0.27
Net power and purchased energy costs	3.03	3.23		(0.20	)	3.37	3.61		(0.24	)
Alberta Power Pool electricity price ($ /MWh)	40.91	52.12		(11.21	)	50.34	67.73		(17.39	)

Power and purchased energy costs per boe, comprised primarily of electric power costs, decreased for the three months and six months ended June 30 2012 as compared to the same periods in the prior year, reflecting the decline in the average Alberta electricity price. During the first half of 2012, Harvest did not have any risk management contracts relating to electricity.

Transportation and marketing costs relate primarily to delivery of natural gas to Alberta’s natural gas sales hub, the AECO Storage Hub, and the cost of trucking clean crude oil to pipeline receipt points. As a result, the total dollar amount of costs generally fluctuates in relation to our sales volumes. Transportation and marketing expenses decreased by $1.24/boe in the second quarter of 2012 compared to the second quarter of 2011 and by $0.44/boe year-to-date. The primary reason for the decreases is due to reduced oil trucking costs at Hay River and Red Earth after the outage of the Plains Rainbow Pipeline in the second quarter of 2011.

Operating Netback(1)
	Three Months Ended						Six Months Ended
			June 30						June 30
					$/boe						$/boe
($ per boe)	2012		2011		Change		2012		2011		Change
Petroleum and natural gas sales    prior to hedging	51.42		66.73		(15.31	)	54.74		63.05		(8.31	)
Royalties	(7.00	)	(11.23	)	4.23		(8.34	)	(9.40	)	1.06
Operating expenses	(15.98	)	(16.35	)	0.37		(17.06	)	(16.87	)	(0.19	)
Transportation expenses	(0.97	)	(2.21	)	1.24		(1.00	)	(1.44	)	0.44
Operating netback prior to hedging(1)	27.47		36.94		(9.47	)	28.34		35.34		(7.00	)
Hedging gains (losses)(2)	1.33		(2.50	)	3.83		1.05		(1.37	)	2.42
Operating netback after hedging(1)	28.80		34.44		(5.64	)	29.39		33.97		(4.58	)

(1)	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.
(2)	Hedging gains (losses) includes the settlement amounts for crude oil and power contracts.

Harvest’s operating netback represents the net amount realized on a per boe basis after deducting directly related costs. In the second quarter of 2012, operating netback prior to hedging decreased by 26% compared to the second quarter of 2011. For year-to-date 2012, operating netback prior to hedging decreased by 20% when compared to the same period in 2011. The decrease is primarily attributable to decreases in realized commodity prices, partially offset by higher sales volumes and decreases in royalties and transportation costs.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

General and Administrative (“G&A”) Expenses

	Three Months Ended		Six Months Ended
	June 30		June 30
	2012	2011	2012	2011
G&A	17,962	14,817	30,115	28,339
G&A ($/boe )	3.24	2.94	2.73	2.88

For the second quarter of 2012, G&A expenses increased by $3.1 million compared to the second quarter of 2011 mainly due to increases in salaries and consulting fees. For the first six months of 2012, G&A expense totaled $30.1 million, an increase of approximately $1.8 million when compared to the same period in 2011 mainly due to the increase in salaries and consulting fees partially offset by the reversal of a provision for a potential renunciation shortfall on a series of flow through shares that was no longer required. G&A expenses are mainly comprised of salaries and other employee related costs. Harvest does not have a stock option program, however there is a long-term cash incentive program.

Depletion, Depreciation and Amortization (“DD&A”) Expenses

	Three Months Ended		Six Months Ended
	June 30		June 30
	2012	2011	2012	2011
DD&A	147,059	127,934	291,542	249,278
DD&A ($/boe)	26.55	25.41	26.38	25.34

DD&A expenses for the three and six months ended June 30, 2012 increased by $19.1million and $42.3 million, respectively, compared to the same periods in 2011, mainly due to higher sales volumes.

Impairment

In the first quarter of 2012, Harvest recorded a pre-tax impairment charge of $21.8 million (2011 – $ nil) against the South Alberta Gas cash generating unit, as a result of the declining forecasted natural gas prices during the quarter. The fair value was determined based on the total proved plus probable reserves estimated by our independent reserves evaluators using the April 1, 2012 commodity price forecast discounted at a pre-tax discount rate of 10%. No impairment was recognized in the second quarters of 2012 and 2011.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Capital Asset Additions

	Three Months Ended		Six Months Ended
	June 30		June 30
	2012	2011	2012	2011
Drilling and completion	21,902	55,511	146,581	193,208
Well equipment, pipelines and facilities	41,940	40,372	104,369	98,061
Geological and geophysical	2,391	3,132	9,115	13,932
Land and undeveloped lease rentals	2,174	4,410	11,097	10,100
Corporate	290	405	538	1,051
Other	4,034	2,570	8,256	4,922
Total additions before BlackGold	72,731	106,400	279,956	321,274
BlackGold oil sands (“BlackGold”)
Drilling and completion	17,940	359	36,844	5,270
Well equipment, pipelines and facilities	30,225	16,979	39,129	34,107
Geological and geophysical	220	50	936	158
Other	3,519	1,713	6,362	2,341
Total BlackGold additions	51,904	19,101	83,271	41,876
Total additions excluding acquisitions	124,635	125,501	363,227	363,150

Below is a summary of the wells drilled by Harvest and the related drilling and completion expenditures for the three months and six months of 2012. Harvest’s overall success rate in the second quarter was 100%.

	Three Months Ended June 30, 2012				Six Months Ended June 30, 2012
Area	Gross	Net			Gross	Net
Hay River	-	-	$	5,072	27.0	27.0	$	42,234
Red Earth	1.0	1.0		4,741	11.0	10.3		42,806
Rimbey/Markerville/West Central	1.0	0.3		606	5.0	2.8		11,678
SE Saskatchewan	1.0	1.0		1,617	8.0	8.0		9,513
Deep Basin	-	-		1,583	3.0	2.3		18,492
Other areas	6.0	4.6		8,283	19.0	11.9		21,858
Total before BlackGold	9.0	6.9	$	21,902	73.0	62.3	$	146,581
BlackGold	14.0	14.0		17,940	19.0	19.0		36,844
Total	23.0	20.9	$	39,842	92.0	81.3	$	183,425

During the second quarter of 2012, Harvest drilled 9 gross (6.9 net) wells (2011 – 19 gross; 14.4 net) in areas other than BlackGold. Capital asset additions, excluding BlackGold, for the quarter totaled $72.7 million (2011 – $106.4 million), of which $21.9 million (2011 - $55.5 million) was spent on drilling and completion and $41.9 million (2011 - $40.4 million) was spent on well equipment, pipelines and facilities.

For the second quarter, Harvest mainly focused on oil drilling. The drilling programs which started in the first quarter of 2012 in Red Earth and Southeast Saskatchewan continued in the second quarter and are expected to be completed in the third quarter of 2012. Harvest’s Heavy Oil and Kindersley light oil program started with 3 gross operated horizontal heavy oil wells and 2 gross light oil multistage fractured horizontal wells in Kindersley. One non-operated gas well was drilled in the West Central Area.

14

  MANAGEMENT’S DISCUSSION AND ANALYSIS

BlackGold oil sands
During the second quarter of 2012, Harvest continued drilling the first pad of steam assisted gravity drainage (“SAGD”) producer and injector wells and spent $17.9 million drilling 14 gross wells. Harvest invested $30.2 million on the engineering, procurement and construction (“EPC”) of the central processing facility of which $24.4 million related to the use of the remaining construction deposit against the costs incurred by the EPC contractor as a result of the EPC contract amendment. Please see the “Liquidity” section of this MD&A for discussion of the EPC contract amendment and its financial impact. During the first six months of 2012, Harvest spent $36.8 million drilling 19 gross SAGD producer and injector wells and spent $39.1 million on the engineering, procurement and construction of the central processing facility, including the use of the $24.4 million construction deposit.

Decommissioning and Environmental Remediation Liabilities
Harvest’s Upstream decommissioning and environmental remediation liabilities at June 30, 2012 were $673.4 million (December 31, 2011 - $672.7 million) for future remediation, abandonment, and reclamation of Harvest’s oil and gas properties. The increase of $0.7 million during the first six months of 2012 was mostly a result of new liabilities incurred on new wells of $4.5 million and accretion of $10.1 million, partially offset by $9.1 million of settlement expenditures and a $4.6 million change in estimate. Please refer to note 7 of our unaudited interim consolidated financial statements for the three and six months ended June 30, 2012 for a continuity table of our decommissioning and environmental remediation liabilities. The total of our decommissioning and environmental remediation liabilities are based on management’s best estimate of costs to remediate, abandon and reclaim our wells, pipelines and facilities. The costs will be incurred over the operating lives of the assets with the majority being at or after the end of reserve life. Please refer to the “Contractual Obligations and Commitments” section of this MD&A for the payments expected for each of the next five years and thereafter in respect of our decommissioning and environmental remediation liabilities.

15

  MANAGEMENT’S DISCUSSION AND ANALYSIS

DOWNSTREAM OPERATIONS

	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011
FINANCIAL
Refined products sales(1)	1,280,221		515,146		2,435,627		1,518,877
Purchased products for processing and resale(1)	1,238,803		477,012		2,340,519		1,369,025
Gross margin(2)	41,418		38,134		95,108		149,852
Expenses
Operating	30,536		25,723		57,669		51,806
Power and purchased energy	25,535		20,136		72,883		47,992
Marketing	989		1,239		2,354		2,933
General and administrative	150		441		300		882
Depreciation and amortization	26,737		22,276		53,306		41,676
Operating income (loss)(2)	(42,529	)	(31,681	)	(91,404	)	4,563
Capital asset additions	6,538		108,741		19,801		144,620
OPERATING
Feedstock volume (bbl/d)(3)	114,552		38,016		107,276		67,563
Yield (% of throughput volume)(4)
Gasoline and related products	31%		33%		31%		32%
Ultra low sulphur diesel and jet fuel	41%		41%		42%		37%
High sulphur fuel oil	24%		25%		24%		28%
Total	96%		99%		97%		97%
Average refining gross margin (US$/bbl)(5)	2.71		8.09		3.58		10.21

(1)	Refined product sales and purchased products for processing and resale are net of intra-segment sales of $164.4 million and $313.2 million for the three and six months ended June 30, 2012, respectively (2011 - $124.4 million and $240.7 million), reflecting the refined products produced by the refinery and sold by the marketing division.
(2)	These are non-GAAP measures; please refer to “Non-GAAP Measures” in this MD&A.
(3)	Barrels per day are calculated using total barrels of crude oil feedstock and vacuum gas oil.
(4)	Based on production volumes after adjusting for changes in inventory held for resale.
(5)	Average refining gross margin is calculated based on per barrel of feedstock throughput.

Refining Benchmark Prices
	Three Months Ended June 30				Six Months Ended June 30
	2012	2011	Change		2012	2011	Change
WTI crude oil (US$/bbl)	93.49	102.56	(9%	)	98.21	98.33	-
Brent crude oil (US$/bbl)	109.01	117.17	(7%	)	113.64	111.09	2%
Brent – WTI differential (US$/bbl)	15.52	14.61	6%		15.43	12.76	21%
Refined product prices
RBOB(1)(US$/bbl)	123.97	130.40	(5%	)	126.02	121.14	4%
Heating Oil(1)(US$/bbl)	121.65	128.06	(5%	)	127.09	123.05	3%
High Sulphur Fuel Oil(2)(US$/bbl)	98.74	100.95	(2%	)	103.55	94.77	9%
U.S. / Canadian dollar exchange rate	0.990	1.033	(4%	)	0.995	1.024	(3%	)

(1)	Market prices sourced from NYMEX.
(2)	Market price sourced from Platts.

16

  MANAGEMENT’S DISCUSSION AND ANALYSIS

Summary of Gross Margins
	Three Months Ended June 30
	2012			2011
		Volumes(4)	(US$/bbl)(5)		Volumes(4)		(US$/bbl)(5)
Refinery
Sales
Gasoline products	414,195	3,433	119.44	151,725	1,193	$	131.38
Distillates	572,210	4,636	122.19	220,843	1,760		129.62
High sulphur fuel oil	263,747	2,738	95.37	102,117	1,061		99.42
Total sales	1,250,152	10,807	114.52	474,685	4,014		122.16
Feedstocks(1)
Crude oil	1,021,192	9,732	103.88	337,646	3,143		110.97
Vacuum gas oil (“VGO”)	81,764	692	116.97	34,633	316		113.21
Total feedstocks	1,102,956	10,424	104.75	372,279	3,459		111.18
Other(2)	118,690			75,322
Purchased products for processing and resale	1,221,646			447,601
Refinery gross margin(3)	28,506		2.71	27,084			8.09
Marketing
Sales	194,512			164,817
Cost of products sold	181,600			153,767
Marketing gross margin(3)	12,912			11,050
Total gross margin(3)	41,418			38,134

(1)	Cost of feedstock includes all costs of transporting the crude oil to the refinery in Newfoundland.
(2)	Includes inventory adjustments, additives and blendstocks.
(3)	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A. Per barrel amount is determined using throughput volume.
(4)	Volumes are in 000’s bbls. Sales volumes represent the quantity of refined products sold, whereas feedstock volumes reflect our throughput.
(5)	Translated using using the average US/Canadian exchange rate for each period.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Six Months Ended June 30
	2012			2011
		Volumes(4)	(US$/bbl)(5)		Volumes(4)	(US$/bbl)(5 )
Refinery
Sales
Gasoline products	764,296	6,252	121.64	497,608	4,387	116.15
Distillates	1,109,871	8,632	127.93	616,183	5,021	125.67
High sulphur fuel oil	502,991	5,012	99.86	323,427	3,638	91.04
Total sales	2,377,158	19,896	118.88	1,437,218	13,046	112.81
Feedstocks(1)
Crude oil	2,015,666	18,151	110.49	1,148,709	11,805	99.64
Vacuum gas oil (“VGO”)	164,365	1,373	119.11	44,683	423	108.17
Total feedstocks	2,180,031	19,524	111.10	1,193,392	12,228	99.94
Other(2)	126,905			121,939
Purchased products for processing and resale	2,306,936			1,315,331
Refinery gross margin(3)	70,222		3.58	121,887		10.21
Marketing
Sales	371,663			322,400
Cost of products sold	346,777			294,435
Marketing gross margin(3)	24,886			27,965
Total gross margin(3)	95,108			149,852

(1)	Cost of feedstock includes all costs of transporting the crude oil to the refinery in Newfoundland.
(2)	Includes inventory adjustments, additives and blendstocks.
(3)	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A. Per barrel amount is determined using throughput volume.
(4)	Volumes are in 000’s bbls. Sales volumes represent the quantity of refined products sold, whereas feedstock volumes reflect our throughput.
(5)	Translated using using the average US/Canadian exchange rate for each period.

Feedstock throughput averaged 114,552 bbl/d in the second quarter of 2012, an increase of 201% from 38,016 average daily throughput in the second quarter of the prior year. The feedstock throughput for the six months ended June 30, 2012 was 107,276 bbl/d, an increase of 59% from 67,563 bbl/d for the same period in 2011. The 2012 average daily rate reflects normal operations and near maximum utilization rates whereas the prior year reflects the impact of the planned shutdown of the refinery units for turnaround work.

The two tables below provide a comparison between each of the product crack spreads realized by our refinery and the benchmark crack spreads for the three and six months ended June 30, 2012.

	Three Months Ended June 30
	2012			2011
	Refinery	Benchmark	Difference	Refinery	Benchmark	Difference
Gasoline products (US$/bbl)(1)	14.69	14.96	(0.27)	20.20	13.23	6.97
Distillates (US$/bbl)(1)	17.44	12.64	4.80	18.44	10.89	7.55
High Sulphur Fuel Oil (US$/bbl)(2)	(9.38)	(10.27)	0.89	(11.76)	(16.22)	4.46

(1)	Market prices sourced from NYMEX.
(2)	Market price sourced from Platts.

18

  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Six Months Ended June 30
	2012			2011
	Refinery	Benchmark	Difference	Refinery	Benchmark	Difference
Gasoline products (US$/bbl)(1)	10.54	12.38	(1.84)	16.21	10.05	6.16
Distillates (US$/bbl)(1)	16.83	13.45	3.38	25.73	11.96	13.77
High Sulphur Fuel Oil (US$/bbl)(2)	(11.24)	(10.09)	(1.15)	(8.90)	(16.32)	7.42

(1)	Market prices sourced from NYMEX.
(2)	Market price sourced from Platts.

Our product crack spreads are different from the benchmarks due to several factors including, the timing of refinery sales and feedstock purchases differing from the calendar month benchmarks, transportation costs, sour crude differentials, quality differentials and variability in our throughput volume over a given period of time. As well our distillate products crack spread reflects the higher quality distillate products produced by our refinery as compared to the quality implicit in the heating oil benchmark. Our refinery sales also include products for which market prices are not reflected in the benchmarks (such as hydrocracker bottoms that are sold at spot market prices with a premium to the high sulphur fuel oil benchmark). Although our product cracks are similar to benchmark, our overall gross margin is lower than benchmark cracks as a result of purchasing blendstocks to meet summer gasoline specifications, additives to meet product specifications, the build of unfinished saleable product which are recorded at a value lower than cost, and inventory write-downs discussed below. These costs are included in “other” in the Summary of Gross Margin Table above.

Our overall gross margin of US$2.71/bbl for the three months ended June 30, 2012 is 67% less than our gross margin of US$8.09/bbl in the prior year. Similarly our overall gross margin of US$3.58/bbl for the six months ended June 30, 2012 is 65% less than our gross margin of US$10.21/bbl in the prior year. The decrease in gross margin is mainly a result of three factors: the decrease in our sour crude differential of US$1.07 and US$8.30 respectively for the three and six months ended June 30, 2012 contributed to the decrease in our refining realized product crack spreads despite the improved benchmark crack spreads; the significant decline in product prices during the three months ended June 30, 2012 translated into realized margin decreases for actual production and sales; and, as a result of the decrease in market prices during the three months ended June 30, 2012, our gross margin has been negatively impacted by $11.7 million of inventory impairments. The impact of changes in our inventory value is reflected in the “other” category of the feedstock costs.

Our cost of feedstock in the second quarter of 2012 reflected a US$4.26/bbl discount to the benchmark Brent crude oil as compared to a discount of US$5.99/bbl in the same period of the prior year. Similarly, our cost of feedstock for the six months ended June 30, 2012 reflected a US$2.54/bbl discount to the benchmark Brent crude oil as compared to a discount of US$11.15/bbl for the same period in 2011. The decrease in our feedstock cost differential to the benchmark during the three and six months ended June 30, 2012 as compared to 2011 reflects the decrease in our realized sour crude differential.

During the three and six months ended June 30, 2012, the Canadian dollar weakened as compared to the US dollar. The weakening of the Canadian dollar in 2012 has had a negative impact to the contribution from our refinery operations relative to the prior year as substantially all of our gross margin, cost of purchased energy and marketing expense are denominated in U.S. dollars.

19

  MANAGEMENT’S DISCUSSION AND ANALYSIS

Operating Expenses
	Three Months Ended June 30
	2012			2011
	Refining	Marketing	Total	Refining	Marketing	Total
Operating cost	25,963	4,573	30,536	20,922	4,801	25,723
Power and purchased energy	25,535	–	25,535	20,136	–	20,136
	51,498	4,573	56,071	41,058	4,801	45,859
($/bbl of feedstock throughput)
Operating cost	2.49	–	–	6.05	–	–
Power and purchased energy	2.45	–	–	5.82	–	–
	4.94	–	–	11.87	–	–

	Six Months Ended June 30
	2012			2011
	Refining	Marketing	Total	Refining	Marketing	Total
Operating cost	47,821	9,848	57,669	42,499	9,307	51,806
Power and purchased energy	72,883	–	72,883	47,992	–	47,992
	120,704	9,848	130,552	90,491	9,307	99,798
($/bbl of feedstock throughput)
Operating cost	2.45	–	–	3.48	–	–
Power and purchased energy	3.73	–	–	3.92	–	–
	6.18	–	–	7.40	–	–

During the three and six months ended June 30, 2012, refining operating costs were higher than the prior year, yet the costs per barrel of feedstock throughput decreased 59% and 30% respectively. Our 2011 results reflect lower operating costs, lower throughput volumes and higher cost per barrel of throughput due to the planned shutdown of the units for major maintenance work.

Purchased energy, consisting of low sulphur fuel oil (“LSFO”) and electricity, is required to provide heat and power to refinery operations. In the second quarter of 2011, the refinery was shut down for planned major maintenance with significantly lower energy requirements. Purchased energy costs in the second quarter of 2012 was higher than the costs in the second quarter of 2011 reflecting normal operations for 2012. The higher energy consumption in 2012 also reflects higher fuel prices of $1.7 million for the three months ended June 30, 2012 and $11.8 million for the six months ended June 30, 2012 as well as higher electricity costs of $0.9 million and $1.0 million for the three and six months ended June 30, 2012 respectively.

Capital Asset Additions
Capital spending for the three and six months ended June 30, 2012 totaled $6.5 million and $19.8 million respectively (2011 - $108.7 million and $144.6 million respectively) relating to various capital improvement projects including $0.8 million and $4.1 million respectively (2011 - $24.9 million and $40.8 million respectively) for the debottlenecking project. Prior year capital expenditures included significant costs related to the turnaround, replacement of catalysts and addition of the packinox and naphtha hydrotreater heat exchangers.

20

  MANAGEMENT’S DISCUSSION AND ANALYSIS

Depreciation and Amortization Expense
	Three Months Ended June 30		Six Months Ended June 30
	2012	2011	2012	2011
��Refining	25,829	21,349	51,438	39,828
Marketing	908	927	1,868	1,848
Total depreciation and amortization	26,737	22,276	53,306	41,676

The process units are amortized over an average useful life of 20 to 30 years and turnaround costs are amortized over 2 to 4 years.

RISK MANAGEMENT, FINANCING AND OTHER

Cash Flow Risk Management
The Company enters into crude oil and foreign exchange contracts to reduce the volatility of cash flows from some of its forecast sales. Harvest designates all of its crude oil derivative contracts and certain foreign exchange contracts as cash flow hedges, which are entered into for periods consistent with the forecast petroleum sales. The following is a summary of Harvest’s risk management contracts outstanding at June 30, 2012:

Contracts Designated as Hedges
Contract Quantity	Type of Contract	Term	Contract Price		Fair Value
4,200 bbls/day	Crude oil price swap	Jun – Dec 2012	US $111.37/bbl	$	19,542
US $468/day	Foreign exchange swap	Jun – Dec 2012	$ 1.0236 Cdn/US		274
				$	19,816

The following is a summary of Harvest’s realized and unrealized (gains) losses on risk management contracts:

	Three Months Ended June 30
	2012				2011
Contracts not designated as hedges	Currency		Power		Currency		Total
Realized (gains) losses	154		(333	)	–		(333	)
Unrealized (gains) losses	67		595		(29	)	566
(Gains) losses recognized in net income	221		262		(29	)	233
Contracts designated as hedges	Crude Oil						Crude Oil
Realized (gains) losses
Reclassified from other comprehensive income     (“OCI”) to revenues, before tax	(7,517	)					12,602
Ineffective portion recognized in net income	20						349
	(7,497	)					12,951
Unrealized (gains) losses
Recognized in OCI, net of tax	(12,645	)					(41,758	)
Ineffective portion recognized in net income	127						(412	)
	(12,518	)					(42,170	)
Total (gains) losses from all risk management contracts
Recognized in OCI, net of tax	(7,015	)					(50,994	)
Recognized in revenues	(7,517	)					12,602
Recognized in net income outside of revenues	368						170

21

  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Six Months Ended June 30
	2012		2011
Contracts not designated as hedges	Currency		Power
Realized (gains) losses	154		(2,616	)
Unrealized (gains) losses	–		(2,959	)
(Gains) losses recognized in net income	154		(5,575	)
Contracts designated as hedges	Crude Oil		Crude Oil
Realized (gains) losses
Reclassified from other comprehensive income (“OCI”) to revenues, before tax	(11,696	)	15,637
Ineffective portion recognized in net income	20		408
	(11,676	)	16,045
Unrealized (gains) losses
Recognized in OCI, net of tax	(8,165	)	872
Ineffective portion recognized in net income	(77	)	(126	)
	(8,242	)	746
Total (gains) losses from all risk management contracts
Recognized in OCI, net of tax	306		(10,588	)
Recognized in revenues	(11,696	)	15,637
Recognized in net income outside of revenues	97		(5,293	)

Financing Costs
	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011
Bank loan	4,079		1,413		7,543		3,046
Convertible debentures	12,330		12,452		24,661		24,779
Senior notes	9,066		8,702		18,090		17,479
Amortization of deferred finance charges	255		257		511		538
Interest and other financing charges	25,730		22,824		50,805		45,842
Capitalized interest	(3,355	)	(1,987	)	(6,247	)	(3,284	)
	22,375		20,837		44,558		42,558
Accretion of decommissioning liabilities and    environmental remediation liabilities	5,177		6,047		10,330		11,843
Total finance costs	27,552		26,884		54,888		54,401

Interest and other financing charges for the three and six months ended June 30, 2012, including the amortization of deferred finance charges increased by $2.9 million and $5.0 million, respectively, compared to the same periods in 2011 mainly due to the increased interest expense on Harvest’s bank loan as a result of the increased amount of loan principal outstanding. For the three months and six months ended June 30, 2012, interest charges on our bank loan reflected an effective interest rate of 2.84% (2011 – 2.94% and 2.99% respectively).

22

  MANAGEMENT’S DISCUSSION AND ANALYSIS

Currency Exchange
Currency exchange gains and losses are attributed to the changes in the value of the Canadian dollar relative to the U.S. dollar on our U.S. dollar denominated 6^7/8% senior notes and on any other U.S. dollar denominated monetary assets or liabilities. At June 30, 2012, the Canadian dollar relative to the U.S. dollar weakened compared to the exchange rate as at both March 31, 2012 and December 31, 2011, resulting in an unrealized foreign exchange loss of $3.6 million (2011 - $1.5 million gain) and $0.8 million (2011 - $11.1 million gain) for the three and six months ended June 30, 2012, respectively. Harvest recognized a realized foreign exchange gain of $2.3 million (2011 - $ nil) and a $0.7 million gain (2011 - $0.2 million gain) for the three and six months ended June 30, 2012, respectively, as a result of the settlement of U.S. dollar denominated transactions.

The cumulative translation adjustment recognized in other comprehensive income results from the translation of the Downstream operation’s U.S. dollar functional currency financial statements to Canadian dollars. During the second quarter of 2012, Downstream recognized a net cumulative translation gain of $16.0 million (2011 - $5.0 million loss), which resulted from the weakening of the Canadian dollar relative to the U.S. dollar at June 30, 2012 as compared to March 31, 2012. During the first six months of 2012, Downstream recognized a modest net cumulative translation loss of $0.1 million (2011 - $28.9 million loss), as the value of the Canadian dollar relative to the U.S. dollar at both June 30, 2012 and December 31, 2011 were comparable. As Downstream’s functional currency is U.S. dollars, the strengthening of the U.S. dollar would result in gains from decommissioning liabilities, pension obligations, accounts payable and other balances that are denominated in Canadian dollars, which partially offset the unrealized losses recognized on the senior notes and Upstream U.S. dollar denominated monetary items.

Deferred Income Taxes
For the three and six months ended June 30, 2012, Harvest recorded a deferred income tax recovery of $15.8 (2011 – 10.8 million) million and $38.5 million (2011 - $7.1 million) respectively. Our deferred income tax liability will fluctuate during each accounting period to reflect changes in the respective temporary differences between the book value and tax basis of their assets as well as further legislative tax rate changes. Currently, the principal source of our temporary differences is the net book value of the Company’s property, plant and equipment and the unclaimed tax pools.

LIQUIDITY

Cash from operating activities for the three and six months ended June 30, 2012 was $70.9 and $156.0 million respectively, compared to $107.6 million and $254.4 million for the same periods in 2011. For the second quarter of 2012, the change in non-cash working capital was a deficit of $31.5 million (2011 – deficit of $16.1 million) and $3.4 million (2011 – $4.3 million) was incurred in the settlement of decommissioning liabilities and environmental provision. For the first six months of 2012, the change in non-cash working capital was a deficit of $39.2 million (2011 – deficit of $48.9 million) and $10.0 million (2011 – $6.2 million) was incurred in the settlement of decommissioning liabilities and environmental provision.

The cash contribution from Harvest’s Upstream operations was $141.0 million in the second quarter of 2012, a decrease of $17.6 million as compared to the same quarter in 2011 mainly due to lower operating netback. The cash deficiency from Harvest’s Downstream operations was $15.0 million in the second quarter of 2012, an increase of $5.5 million as compared to the same quarter in 2011 as a result of higher operating expenses, partially offset by higher gross margin.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

For the six months ended June 30, 2012, the cash contribution from Harvest’s Upstream operations was $288.0 million in the second quarter of 2012, a decrease of $17.8 million as compared to the same period in 2011 mainly due to lower operating netback. The cash deficiency from Harvest’s Downstream operations was $38.8 million in the first six months of 2012, an increase of $85.1 million as compared to the same period in 2011 as a result of a lowers gross margin and higher power and purchased energy expenses.

For the second quarter of 2012 Harvest’s financing activities provided $108.4 million (2011 - $141.6 million) of cash from the net borrowings using the credit facility. For the six months ended June 30 2012, $284.2 million (2011 - $160.3 million) of net cash was borrowed under the credit facility. During the first six months of the prior year, $505.4 million of cash was invested into Harvest by our sole shareholder, Korea National Oil Corporation (“KNOC”) to fund the acquisition of the Hunt assets.

For the three and six months ended June 30, 2012, Harvest funded $132.4 million (2011 - $234.7 million) and $382.3 million (2011 – $511.2 million), respectively, of capital expenditures and net asset acquisition activity with cash generated from operating activities and financing activities.

Harvest had a working capital deficiency of $153.6 million at June 30, 2012, as compared to a $265.6 million deficiency at December 31, 2011. The improvement in our working capital deficiency at June 30, 2012 compared to December 31, 2011 was primarily due to the decrease in accrued capital expenditures during the period. The Company’s working capital is expected to fluctuate from time to time, and will be funded from cash flows from operations and borrowings from Harvest’s credit facility, as required.

Through a combination of cash available at June 30, 2012, cash from operating activities and the available undrawn amount from the credit facility, it is anticipated that Harvest will have adequate liquidity to fund future operations, debt repayments and forecasted capital expenditures (excluding major acquisitions). Refer to the “Contractual Obligations and Commitments”section above for Harvest’s future commitments and the discussion below on certain significant items.

BlackGold Oil Sands Project
On May 30, 2012, Harvest amended certain aspects of its BlackGold oil sands project engineering, procurement and construction (“EPC”) contract, including revising the compensation terms from a lump sum price to a cost reimbursable price and confirming greater Harvest control over project execution. The cost pressures and resultant contract changes are expected to increase the net EPC costs to approximately $520 million from the lump sum contract amount of $311 million, after allowing for certain costs which are not reimbursable to the EPC contractor. Harvest and the EPC contractor also agreed to apply the cumulative progress payments made under the lump sum contract and the remaining deposit of $24.4 million towards costs incurred to date. Under the amended EPC contract, a maximum of approximately $101 million of project costs will be paid in equal installments, without interest, over 10 years commencing on April 30, 2014. As at June 30, 2012, $2.0 million of such costs have been incurred. First oil production of 10,000 bbl/d from phase 1 is still expected in 2014.

The Company remains engaged in the drilling of 30 wells (15 well pairs) which is expected to be completed by the end of 2012. Five wells were drilled during the first quarter of 2012 and an additional fourteen wells were drilled in the second quarter. Engineering of the project is now approximately 70% complete and the site has been cleared and graded and piling work is underway. Other near-term activities include completion of the detailed engineering work, and the construction of major equipment. Phase 2 of the project, which is targeted to increase production capacity to 30,000 bbl/d, is in the regulatory approval process and approval is anticipated late this year or early 2013.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Harvest had originally budgeted 2012 capital spending of $215 million for the BlackGold oil sands project which has now been reduced to approximately $160 million. Activities that will be deferred are primarily related to facility construction. Harvest plans to fund the capital expenditures with cash flows from operating activities and the undrawn amount from the credit facility. As of June 30, 2012, Harvest has spent $107.7 million (including the $31.1 million deposit) on the EPC contract and has invested $205.6 million in the entire project since acquiring the BlackGold assets in 2010.

Contractual Obligations and Commitments
Harvest has contractual obligations and commitments entered into in the normal course of operations including the purchase of assets and services, operating agreements, transportation commitments, purchase commitments, royalty obligations, and land lease obligations. These obligations are of a recurring and consistent nature and impact cash flow in an ongoing manner. As at June 30, 2012, Harvest has the following significant contractual commitments:

	Maturity
	1 year	2-3 years	4-5 years	After 5 years	Total
Debt repayments(1)	106,796	1,270,228	–	509,050	1,886,074
Debt interest payments(1)	102,238	148,669	77,320	8,749	336,976
Purchase commitments(2)	234,712	152,480	20,000	60,000	467,192
Operating leases	12,007	18,381	6,956	1,572	38,916
Transportation agreements(3)	8,555	12,635	3,700	422	25,312
Feedstock & other purchase
commitments(4)	709,089	–	–	–	709,089
Employee benefits(5)	6,111	9,982	7,380	2,199	25,672
Decommissioning and
environmental remediation	23,847	47,694	34,880	1,349,715	1,456,136
liabilities(6)
Total	1,203,355	1,660,069	150,236	1,931,707	4,945,367

(1)	Assumes constant period end foreign exchange rate.
(2)	Relates to drilling commitments, AFE commitments, BlackGold oil sands project commitment and Downstream capital commitments.
(3)	Relates to firm transportation commitments.
(4)	Includes commitments to purchase refinery crude stock under the supply and offtake agreement, purchased fuel and other additives.
(5)	Relates to the expected contributions to employee benefit plans and long-term incentive plan payments.
(6)	Represents the undiscounted obligation by period.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

CAPITAL RESOURCES
The following table summarizes our capital structure as at June 30, 2012 and December 31, 2011 and provides the key financial ratios defined in Harvest’s credit facility agreement.

	June 30, 2012	December 31, 2011
Debts
Bank loan(1)	643,051	358,885
Convertible debentures, at principal amount	733,973	733,973
Senior notes, at principal amount (US$500 million)(2)	509,050	508,500
	1,886,074	1,601,358
Shareholder’s Equity
386,078,649 common shares issued(3)	3,303,277	3,453,644
	5,189,351	5,055,002
Financial Ratios(4)(5)
Senior Debt to Annualized EBITDA(6)	1.42	0.73
Total Debt to Annualized EBITDA(7)	3.82	2.72
Senior Debt to Total Capitalization(6)(8)	15%	10%
Total Debt to Total Capitalization(7)(8)	41%	36%

(1)	The bank loan net of deferred financing costs is $640.2 million (2011 - $355.6 million).
(2)	Principal amount converted at the period end exchange rate.
(3)	As at August 8, 2012, the number of common shares issued is 386,078,649.
(4)	Calculated based on Harvest’s credit facility covenant requirements (see note 10 of the June 30, 2012 financial statements).
(5)	The financial ratios and their components are non-GAAP measures; please refer to the “Non-GAAP Measures” section of this MD&A.
(6)	Senior debt includes bank loan of $640.2 million (2011 - $355.6 million), letters of credit of $8.9 million (2011 - $8.7 million), and guarantees of $78.5 million (2011- $92.1 million) at June 30, 2012.
(7)	Total debt includes the senior debt, convertible debentures of $740.4 million (2011 - $742.1 million) and senior notes of $497.0 million (2011 - $495.7 million) at June 30, 2012.
(8)	Total capitalization includes total debt and shareholder’s equity less equity attributed to BlackGold of $458.8 million at June 30, 2012 (2011 - $459.9 million).

Under the credit facility agreement, Harvest is required to maintain certain financial ratios. On June 29, 2012, Harvest amended the credit facility agreement to revise the maximum allowable total debt to annualized EBITDA ratio from 3.5:1 to the following:

Twelve months ending	Total Debt to Annualized EBITDA
June 30, 2012	4.25:1.0 or less
September 30, 2012	4.25:1.0 or less
December 31, 2012	4.00:1.0 or less
March 31, 2013	3.75:1.0 or less
June 30, 2013 and thereafter	3.50:1.0 or less

Except for the above, all other terms to the credit facility agreement remain unchanged.

Subsequent to June 30, 2012, Harvest agreed with its lenders to extend the credit facility agreement by one year to April 30, 2016.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

OFF BALANCE SHEET ARRANGEMENTS
As of June 30, 2012, there were no off balance sheet arrangements in place.

RELATED PARTY TRANSACTIONS
For the three and six months ended June 30, 2012, Harvest billed KNOC and certain subsidiaries for a total of $0.3 million and $0.8 million respectively (2011 - $0.2 million and $0.4 million) primarily related to technical services provided by Harvest’s Global Technology and Research Centre (“GTRC”). As at June 30, 2012, $0.2 million (2011 - $1.1 million) remained outstanding from KNOC in accounts receivable. KNOC billed Harvest $0.1 million for the six months ended June 30, 2012 (2011 – $ nil) for reimbursement to KNOC for secondee salaries. As at June 30, 2012, $0.1 million (2011 - $0.6 million) remains outstanding in accounts payable.

KNOC Trading Corporation (“KNOC Trading”) is a wholly owned subsidiary of North Atlantic Refining Limited, which is a wholly owned subsidiary of Harvest. KNOC Trading receives revenue from ANKOR E&P Holdings Corp. (“ANKOR”), a wholly owned U.S. subsidiary of KNOC, on a monthly basis by providing oil marketing service such as pipeline arrangement, reviewing oil marketing agreements, and other services. For the three and six months ended June 30, 2012, all of KNOC Trading’s revenue of $0.2 million and $0.3 million respectively (2011 - $ nil) were derived from ANKOR.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

SUMMARY OF QUARTERLY RESULTS
The following table and discussion highlights our second quarter of 2012 results relative to the preceding 7 quarters:

	2012				2011							2010
	Q2		Q1		Q4		Q3		Q2		Q1	Q4		Q3
FINANCIAL
Revenues	1,533,808		1,426,140		1,462,535		837,381		782,041		1,248,924	1,301,348		1,001,203
Net income (loss)	(73,293	)	(72,081	)	(73,885	)	(49,204	)	(19,529	)	37,961	(12,333	)	(26,082	)
Cash from operating activities	70,850		85,110		144,625		161,499		107,536		146,828	142,134		97,412
Total long-term financial debt	1,770,748		1,652,424		1,486,170		1,509,773		1,384,862		1,244,825	1,239,024		1,251,658
Total assets	6,277,496		6,322,250		6,284,370		6,483,568		6,121,547		6,041,118	5,388,740		5,303,486
OPERATIONS
Upstream
Daily sales volumes (boe/d)	60,874		60,550		61,324		58,548		55,338		53,331	50,054		47,777
Realized price prior to hedges ($/boe)	51.42		58.07		64.61		57.85		66.73		59.19	56.03		52.71
Downstream
Average daily throughput (bbl/d)	114,552		100,000		88,824		41,756		38,016		97,438	111,317		96,514
Average refining margin (loss) ($US/bbl)	2.71		4.58		(4.14	)	10.44		8.09		10.96	6.13		3.02

The quarterly revenues and cash from operating activities are mainly impacted by the Upstream sales volumes, realized prices and operating expenses and Downstream throughput volumes, cost of feedstock and realized prices. Significant items that impacted Harvest’s quarterly revenues include:

• Revenues were highest in the second quarter of 2012 as a result of the refinery operating at near capacity. Revenues were second highest during the fourth quarter of 2011, reflecting higher commodity prices and stronger sales volumes in the Upstream operations.
• The lower revenue in the second and third quarters of 2011 was due to lower Downstream sales as a result of a planned shutdown, partially offset by increased Upstream sales from the assets acquired from Hunt in the first quarter 2011 and higher commodity prices.
• The increasing Upstream sales volumes since the third quarter of 2010 were mainly attributable to the acquisition of oil and gas assets in the third quarter of 2010 and first quarter of 2011, combined with our active drilling programs.
• Downstream’s refining margin/bbl increased in the first and third quarter of 2011, reflecting the improving global refining crack spreads during these periods. However the weaker margins experienced in the three most recent quarters reflect the decrease in the sour-crude differential from the Brent benchmark price for crude oil.

Net income (loss) reflects both cash and non-cash items. Changes in non-cash items including deferred income tax, DD&A expense, accretion of decommissioning and environmental remediation liabilities, impairment of long-lived assets, unrealized foreign exchange gains and losses, and unrealized gains and losses on risk management contracts impact net income (loss) from period to period. For these reasons, the net income (loss) may not necessarily reflect the same trends as revenues or cash from operating activities, nor is it expected to.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

The significant increase in total assets in the first quarter of 2011 was due to the February 2011 acquisition of oil and gas properties from Hunt while the increases in other quarters is mainly attributable to organic additions from Harvest’s capital program.

OUTLOOK
Over the past year, Harvest’s Downstream business has experienced weak refining margins, longer than anticipated downtime and associated increases in cost from the large scale maintenance activities performed in 2011. In conjunction, our Upstream business has been managing continued weakness in natural gas prices in combination with softening Canadian crude oil prices. Maintaining capital discipline and sensibly managing our assets is an integral part of managing our balance sheet through these market conditions.

Upstream
The Upstream capital budget for 2012 has been revised from $435 million to $411 million. Our focus continues on investing in opportunities that provide favorable economics, preserving Harvest’s financial strength for future activity.

As in prior years, the majority of Harvest’s 2012 capital spending and drilling activity takes place within the first few months of the year as we have a very active winter drilling program. Production in the second quarter was 60,847 boe/d for an average of 60,712 boe/d for the year to date. Harvest’s 2012 exit production is now expected to be approximately 57,000 boe/d and full year average production to be approximately 59,000 boe/d. Operationally we will focus on our Heavy oil area, Hay River, Ante Creek, Kindersley, Cecil and will continue with setup for drilling Deep Basin liquids rich gas, Red Earth Slave Point oil and Hay River Bluesky oil properties.

There is no change in royalty guidance of 16% of revenue, and average general & administrative costs of $2.80/boe. Based on the actual operating costs incurred to date in 2012, guidance to operating costs has been revised to average approximately $16.50/boe.

Harvest had originally budgeted 2012 capital spending of $215 million for the BlackGold oil sands project; this is now reduced to approximately $160 million. Activities that will be deferred are primarily related to facility construction. First oil production of 10,000 bbl/d from Phase 1 is expected in 2014. ERCB approval for Phase 2 is anticipated late this year or early 2013. Phase 2 expansion of the project is estimated to contribute an additional 20,000 bbl/d.

Downstream
Harvest has reduced the 2012 Downstream capital budget from $120 million to approximately $80 million by deferring $40 million of discretionary projects from 2012 to later years.

Throughput volume is expected to average of 105,000 to 110,000 bbl/d in 2012, with operating costs and purchased energy costs aggregating to approximately $7.00/bbl.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Harvest mitigates commodity price risk through closely monitoring the various commodity markets and establishing commodity price risk management programs, as deemed necessary, to provide stability to its cash flows.

ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES
The preparation of Harvest’s financial and operating results requires management to make judgments, estimates and assumptions in the application of accounting policies that could have a significant impact on our results. Actual results may differ from those estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Further information on the basis of presentation and our significant accounting policies and estimates can be found in the notes to the audited consolidated financial statements for the year ended December 31, 2011. There have been no changes to our critical accounting policies and estimates in the second quarter of 2012.

RECENT PRONOUNCEMENTS
There have been no updates during the second quarter of 2012 to the future accounting policies that were described in the annual MD&A for the year ended December 31, 2011. Harvest is currently assessing the potential impact from the adoption of those new standards.

OPERATIONAL AND OTHER BUSINESS RISKS
Harvest’s operational and other business risks remain unchanged from those discussed in our annual MD&A for the year ended December 31, 2011 as filed on SEDAR atwww.sedar.com.

CHANGES IN REGULATORY ENVIRONMENT
Harvest’s regulatory environment remains unchanged from those discussed in our annual MD&A for the year ended December 31, 2011 as filed on SEDAR atwww.sedar.com.

INTERNAL CONTROL OVER FINANCIAL REPORTING
During the interim period ended June 30, 2012, there were no significant changes in internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.

ADDITIONAL GAAP MEASURE
Harvest uses “operating income (loss)”, an additional GAAP measure that is not defined under International Financial Reporting Standards (“IFRS”) hereinafter also referred to as “GAAP”. The measure is commonly used for comparative purposes in the petroleum and natural gas and refining industries to reflect operating results before items not directly related to operations. Harvest uses this measure to assess and compare the performance of its two operating segments.

NON-GAAP MEASURES
Throughout this MD&A, the Company has referred to certain measures of financial performance that are not specifically defined under GAAP such as “operating netbacks”, “operating netback prior to/after hedging”, “gross margin (loss)”, “cash contribution (deficiency) from operations”, “total debt”, “total financial debt”, “total capitalization”, “Annualized EBITDA”, “senior debt to Annualized EBITDA”, “total debt to Annualized EBITDA”, “senior debt to total capitalization”, and “total debt to total capitalization”.

30

  MANAGEMENT’S DISCUSSION AND ANALYSIS

“Operating netbacks” are reported on a per boe basis and used extensively in the Canadian energy sector for comparative purposes. “Operating netbacks” include revenues, operating expenses, transportation and marketing expenses, and realized gains or losses on risk management contracts. “Gross margin (loss)” is commonly used in the refining industry to reflect the net funds received from the sale of refined products after considering the cost to purchase the feedstock and is calculated by deducting purchased products for resale and processing from total revenue. “Cash contribution (deficiency) from operations” is calculated as operating income (loss) adjusted for non-cash items. The measure demonstrates the ability of the each segment of Harvest to generate the cash from our operations necessary to repay debt, make capital investments, and fund the settlement of decommissioning and environmental remediation liabilities. “Total debt”, “total financial debt”, “total capitalization”, and “Annualized EBITDA” are used to assist management in assessing liquidity and the Company’s ability to meet financial obligations. “Senior debt to Annualized EBITDA”, “total debt to Annualized EBITDA”, “senior debt to total capitalization” and “total debt to total capitalization” are terms defined in Harvest’s credit facility agreement for the purpose of calculation of our financial covenants. The non-GAAP measures do not have any standardized meaning prescribed by GAAP and may not be comparable to similar measures used by other issuers. The determination of the non-GAAP measures have been illustrated throughout this MD&A, with reconciliations to IFRS measures and/or account balances, except for Annualized EBITDA and cash contribution (deficiency) which are shown below.

Annualized EBITDA
Annualized EBITDA is defined in Harvest’s credit facility agreement as earnings before finance costs, income tax expense or recovery, DD&A, exploration and evaluation costs, impairment of assets, unrealized gains or losses on risk management contracts, unrealized gains or losses on foreign exchange, gains or losses on disposition of assets and other non-cash items. The following is a reconciliation of Annualized EBITDA to the nearest GAAP measure net loss:

Twelve months rolling:	June 30, 2012		December 31, 2011
Net loss	(268,464	)	(104,657	)
DD&A	680,593		626,698
Finance costs	109,614		109,127
Income tax recovery	(61,298	)	(29,827	)
EBITDA	460,445		601,341
Unrealized gains on risk management contracts	2,263		(746	)
Unrealized gains on foreign exchange	14,488		2,555
Unsuccessful exploration and evaluation costs	23,989		17,757
Impairment of PP&E	21,843		–
Gains on disposition of PP&E	(7,672	)	(7,883	)
Other non-cash items	58		4,795
Adjustments on acquisitions and dispositions(1)	–		6,481
Less earnings from non-restricted subsidiaries(1)	(1,344	)	(1,516	)
Annualized EBITDA(1)	514,070		622,784

(1) As stipulated by the credit facility agreement, Annualized EBITDA is a twelve month rolling measure which includes the net income impact from acquisitions or dispositions as if the transaction had been effected at the beginning of the period and excludes earnings attributable to the BlackGold assets and non-restricted subsidiaries.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Cash Contribution (Deficiency) from Operations
Cash contribution (deficiency) from operations represents operating income (loss) adjusted for non-cash expense items within: general and administrative, exploration and evaluation, depletion, depreciation and amortization, gains on disposition of PP&E, risk management contracts gains or losses, impairment on PP&E, and the inclusion of cash interest and realized foreign exchange gains or losses. The measure demonstrates the ability of each segment of Harvest to generate cash from its operations. The most directly comparable additional GAAP measure is operating income (loss). Operating income (loss) as presented in the notes to Harvest’s consolidated financial statements is reconciled to cash contribution (deficiency) from operations below:

	Three months ended June 30
	Downstream				Upstream				Total
	2012		2011		2012		2011		2012		2011
Operating income (loss)	(42,529	)	(31,681	)	(17,704	)	26,730		(60,233	)	(4,951	)
Adjustments for non-cash items:
Operating	770		(166	)	(415	)	–		355		(166	)
General and administrative	–		–		(135	)	(1	)	(135	)	(1	)
Exploration and evaluation	–		–		12,314		4,148		12,314		4,148
Depletion, depreciation and amortization	26,737		22,276		147,059		127,934		173,796		150,210
Gains on disposition of PP&E	–		–		(363	)	(440	)	(363	)	(440	)
Unrealized losses on risk management contracts	–		–		194		154		194		154
Cash contribution (deficiency) fromoperations	(15,022	)	(9,571	)	140,950		158,525		125,928		148,954
Inclusion of items not attributable to segments:
Net cash interest									22,507		21,001
Realized foreign exchange (gains) losses									(2,263	)	25
Consolidated cash contribution from operations									105,684		127,928

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Six months ended June 30
	Downstream			Upstream				Total
	2012		2011	2012		2011		2012		2011
Operating income (loss)	(91,404	)	4,563	(37,469	)	49,950		(128,873	)	54,513
Adjustments for non-cash items:
Operating	(713	)	90	(3,623	)	-		(4,336	)	90
General and administrative	-		-	(197	)	112		(197	)	112
Exploration and evaluation	-		-	16,472		10,239		16,472		10,239
Depletion, depreciation and amortization	53,306		41,676	291,542		249,278		344,848		290,954
Gains on disposition of PP&E	-		-	(469	)	(680	)	(469	)	(680	)
Unrealized (gains) losses on risk management contracts	-		-	(77	)	(3,085	)	(77	)	(3,085	)
Impairment on PP&E	-		-	21,843		-		21,843		-
Cash contribution (deficiency) fromoperations	(38,811	)	46,329	288,022		305,814		249,211		352,143
Inclusion of items not attributable to segments:
Net cash interest								44,821		42,789
Realized foreign exchange gains								(692	)	(165	)
Consolidated cash contribution from operations								205,082		309,519

FORWARD-LOOKING INFORMATION
This MD&A highlights significant business results and statistics from our unaudited consolidated financial statements for the three and six months ended June 30, 2012 and the accompanying notes thereto. In the interest of providing our lenders and potential lenders with information regarding Harvest, including our assessment of our future plans and operations, this MD&A contains forward-looking statements that involve risks and uncertainties.

Such risks and uncertainties include, but are not limited to: risks associated with conventional petroleum and natural gas operations; risks associated with refining and marketing operations; risks associated with the construction of the oil sands project; the volatility in commodity prices, interest rates and currency exchange rates; risks associated with realizing the value of acquisitions; general economic, market and business conditions; changes in environmental legislation and regulations; the availability of sufficient capital from internal and external sources; and, such other risks and uncertainties described from time to time in our regulatory reports and filings made with securities regulators.

Forward-looking statements in this MD&A include, but are not limited to, the forward looking statements made in the “Outlook” section as well as statements made throughout with reference to production volumes, refinery throughput volumes, royalty rates, operating costs, commodity prices, administrative costs, price risk management activities, acquisitions and dispositions, capital spending, reserve estimates, access to credit facilities, income taxes, cash from operating activities, and regulatory changes. For this purpose, any statements that are contained herein that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements often contain terms such as “may”, “will”, “should”, “anticipate”, “expect”, “target”, “plan”, “potential”, “intend”, and similar expressions.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

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

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

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