Harvest Operations 6-K Harvest Operations Reports Q2 2016 Results

  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 condensed interim consolidated financial statements of Harvest Operations Corp. (“Harvest”, “we”, “us”, “our” or the “Company”) for the three and six months ended June 30, 2016 and the MD&A and audited annual consolidated financial statements for the year ended December 31, 2015 together with the accompanying notes. The information and opinions concerning the future outlook are based on information available at August 11, 2016.

In this MD&A, all dollar amounts are expressed in Canadian dollars unless otherwise indicated. Tabular amounts are in millions 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.

Additional information concerning Harvest, including its audited annual consolidated financial statements and 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

FINANCIAL AND OPERATING HIGHLIGHTS

	Three Months Ended June 30				Six Months Ended June 30
	2016		2015		2016		2015
Upstream
Daily sales volumes (boe/d)(1)	34,440		41,716		35,713		42,737
Deep Basin Partnership
Daily sales volumes (boe/d)	6,204		4,898		5,962		3,244
Harvest's share of daily sales volumes (boe/d)(3)	5,087		3,884		4,888		2,561
Average realized price
Oil and NGLs ($/bbl)(2)	39.58		52.10		33.38		46.09
Gas ($/mcf)(2)	1.17		2.54		1.45		2.67
Operating netback prior to hedging($/boe)(3)	8.85		16.92		6.78		13.31
Operating loss(4)	(51.3	)	(134.1	)	(146.6	)	(244.0	)
Cash contribution from operations(3)	15.4		52.5		16.2		71.7
Capital asset additions (excluding acquisitions)	0.7		48.4		2.8		105.0
Corporate acquisition(5)	—		—		—		36.8
Property dispositions, net	(134.2	)	(58.0	)	(138.7	)	(58.5	)
Net wells drilled	—		—		0.3		19.2
Net undeveloped land additions (acres)	5,302		18,206		10,868		38,544
Net undeveloped land dispositions (acres)	(26,281	)	(5,519	)	(33,867	)	(5,519	)
BlackGold
Capital asset additions	0.1		3.8		0.1		64.6
Pre-operating loss(4)(6)	(2.7	)	(5.8	)	(7.2	)	(7.0	)
NET LOSS	(65.7	)	(87.0	)	(78.8	)	(310.5	)

(1)	Excludes volumes from Harvest’s equity investment in the Deep Basin Partnership.
(2)	Excludes the effect of derivative contracts designated as hedges.
(3)	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.
(4)	This is an additional GAAP measure; please refer to “Additional GAAP Measures” in this MD&A.
(5)	Corporate acquisition represents the total consideration for the transaction including working capital assumed.
(6)	BlackGold was substantially completed in Q1 2015, all pre-operating expenses prior to Q1 2015 were capitalized.

REVIEW OF OVERALL PERFORMANCE

Harvest is an energy company with a petroleum and natural gas business focused on the exploration, development and production of assets in western Canada (“Upstream”) and an in-situ oil sands project in the pre-commissioning phase in northern Alberta (“BlackGold”). Harvest is a wholly owned subsidiary of Korea National Oil Corporation (“KNOC”). Our earnings and cash flow from continuing operations are largely determined by the realized prices for our crude oil and natural gas production.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

The latter part of 2014, 2015 and the first six months of 2016 have been challenging for the oil and gas industry. The approximate 54% and 73% percent declines in crude oil and natural gas prices respectively since June 2014 has resulted in widespread reductions in capital spending programs and extensive efforts to reduce costs across the industry. We believe that commodity prices will eventually improve; however, the timing of that improvement is uncertain and we expect continued commodity price and cash flow volatility in the near term. In the meantime, we are focused on identifying sustainable cost reductions as well as keeping our capital program focused on necessary spending to meet our commitments and maintaining assets.

Upstream

• Sales volumes for the second quarter and six months ended June 30, 2016 decreased by 7,276 boe/d and 7,024 boe/d, respectively, as compared to the same periods in 2015. The decreases were primarily due to dispositions of certain non-core producing properties during 2015 and 2016 and natural declines exceeding the volume additions from our drilling program.

• Harvest’s share of Deep Basin Partnership (“DBP”) volumes for the second quarter and six months ended June 30, 2016 increased 1,203 boe/d and 2,327 boe/d, respectively, as compared to the same periods in 2015. The increases are due primarily to the contribution of certain gas assets by Harvest in the fourth quarter of 2015 and volume additions from DBP’s drilling program. The construction of the HK MS Partnership (“HKMS”) natural gas processing plant was completed and operational in early 2015. Strategically, this facility provides the DBP an advantage of access to firm processing capability, the ability to extract maximum liquids from the natural gas produced by DBP wells and will allow DBP to pursue both acquisition and drilling opportunities in the region.

• Operating netback per boe prior to hedging for the second quarter and six months ended June 30, 2016 was $8.85 and $6.78, respectively, decreases of $8.07 and $6.53 from the same periods in 2015. The decreases from 2015 were mainly due to lower realized prices per boe as a result of commodity benchmarks price declines, partially offset by lower operating expenses per boe.

• Operating losses for the second quarter and six months ended June 30, 2016 were $51.3 million and $146.6 million, respectively (2015 –$134.1 million and $244.0 million). The decreases in operating loss from 2015 were due to gains on dispositions of assets, lower impairment expenses, depreciation, depletion and amortization expenses, royalties, operation expenses, general and administrative expenses, partialy offset by lower realized prices and sales volumes.

• Cash contributions from Harvest’s Upstream operations for the second quarter and first six months of 2016 was $15.4 million and $16.2 million, respectively (2015 – $52.5 million and $71.7 million). The decreases in cash contribution were mainly due to lower sales volumes and lower realized prices, partially offset by lower royalties, operating expenses, and general and administrative expenses.

• Capital asset additions of $0.6 million and $2.9 million in the second quarter and first six months of 2016, respectively, were mainly related to well equipment, pipelines and facilities. One gross well (0.3 net) was rig-released during the first six months of 2016.

•  On June 30, 2016, Harvest closed the disposition of all of its oil and gas assets in Saskatchewan for net proceeds of $62.3 million. Together with other less significant dispositions of Upstream assets, Harvest recognized a gain of $17.7 million and $17.3 million for the three and six months ended June 30, 2016, respectively (2015 – losses of $5.8 million and $5.3 million), relating to the de-recognition of PP&E, E&E, goodwill and decommissioning and environmental liabilities.  

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

BlackGold
•	Pre-operating losses for the second quarter and first six months of 2016 were $2.7 million and $7.2 million, respectively (2015 – $5.8 million and $7.0 million, respectively). The pre-operating losses were mainly due to pre-operating and general and administrative expenses.
•	The central processing facility (“CPF’) was substantially completed in early 2015. The decision to complete commissioning of the CPF and commence steam injection depends on a number of factors including the bitumen price environment.
CORPORATE
•	On June 16, 2016 Harvest completed an exchange of a significant portion of its 6⅞% senior notes due 2017 for new 2⅓% senior notes due 2021, at an exchange ratio of US$900 principal amount of the new 2⅓% senior notes for each US$1,000 principal amount of the old 6⅞% senior notes. US$217.5 million of the old 6⅞% senior notes was exchanged for US$195.8 million new 2⅓% senior notes. The extinguishment of the old 6⅞% senior notes resulted in a gain of $19.8 million and a realized foreign exchange gain of $16.3 million. The transaction provides significant saving to Harvest by reducing interest expense by US$9.9 million annually, as well as reduction in principal of US $21.7 million.
•	The net repayment to the credit facility during the second quarter and six months ended June 30, 2016 was $5.9 million and $38.9 million, respectively (2015 - $16.9 million and $266.4 million net borrowings). At June 30, 2016, Harvest had $891.6 million drawn under the credit facility (December 31, 2015 - $926.6 million).
•	The weakening of the Canadian dollar against the U.S. dollar during the latter part of the second quarter of 2016 resulted in net unrealized foreign exchange loss of $13.0 million for the three months ended June 30, 2016 (2015 - $22.8 million gain). The weakening of the U.S. dollar against the Canadian dollar during the first six months of 2016 resulted in net unrealized foreign exchange gain of $105.6 million (2015 - $116.1 million loss). Unrealized foreign exchange gains and losses resulted primarily due to the translation of U.S. dollar denominated debt (including related party loans) into Canadian dollars.
•	During 2015, Harvest amended the terms of its $1.0 billion syndicated revolving credit facility and replaced it with a KNOC guaranteed $1.0 billion syndicated revolving credit facility maturing April 30, 2017. Under the amended credit facility, applicable interest and fees are based on a margin pricing grid based on the Moody’s and S&P credit ratings of KNOC. The financial covenants under the previous credit facility were deleted and replaced with a new covenant: Total Debt to Capitalization ratio of 70% or less. At December 31, 2015, Harvest was in violation of the debt covenant and the carrying value of the credit facility, $923.8 million, was reclassified from long-term debt to a current liability. On February 5, 2016 Harvest’s syndicate banks consented to a waiver of this covenant for the duration of the term of the credit facility and the maturity date remains at April 30, 2017.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

UPSTREAM

Summary of Financial and Operating Results

	Three Months Ended June 30				Six Months Ended June 30
	2016		2015		2016			2015
FINANCIAL							��
Petroleum and natural gas sales(1)	82.8		143.0		153.0			269.4
Royalties	(10.1	)	(12.2	)	(15.9	)		(25.3	)
Revenues and other income	72.7		130.8		137.1			244.1
Expenses
Operating	44.2		65.6		90.9			138.0
Transportation and marketing	1.0		1.7		2.4			2.9
Realized losses (gains) on derivative contracts(3)	0.4		(0.7	)	0.8			0.7
Operating netback after hedging(4)	27.1		64.2		43.0			102.5
General and administrative	13.3		12.9		28.0			31.9
Depreciation, depletion and amortization	66.6		98.8		141.3			197.1
Loss from joint ventures	10.6		10.1		29.1			16.0
Exploration and evaluation	-		3.7		2.1			4.6
Impairment	-		70.7		-			94.2
Unrealized losses (gains) on derivative contracts(5)	5.6		(3.7	)	6.4			(2.6	)
Losses (gains) on disposition of assets	(17.7	)	5.8		(17.3	)		5.3
Operating loss(2)	(51.3	)	(134.1	)	(146.6	)		(244.0	)
Capital asset additions (excluding acquisitions)	0.7		48.4		2.8			105.0
Corporate acquisition(6)	—		—		—			36.8
Property dispositions, net	(134.2	)	(58.0	)	(138.7	)		(58.5	)
OPERATING
Light to medium oil (bbl/d)	6,604		8,695		7,013			9,260
Heavy oil (bbl/d)	9,821		11,969		9,951			12,013
Natural gas liquids (bbl/d)	3,734		3,779		3,772			4,004
Natural gas (mcf/d)	85,688		103,639		89,861			104,757
Total (boe/d)(7)	34,440		41,716		35,713			42,737

(1)	Includes the effective portion of Harvest’s realized natural gas and oil hedges.
(2)	This is an additional GAAP measure; please refer to “Additional GAAP Measures” in this MD&A.
(3)	Realized gains on derivative contracts include the settlement amounts for power, crude oil, natural gas and foreign exchange derivative contracts, excluding the effective portion of realized gains from Harvest’s designated accounting hedges. See “Risk Management, Financing and Other” section of this MD&A for details.
(4)	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.
(5)	Unrealized gains on derivative contracts reflect the change in fair value of derivative contracts that are not designated as accounting hedges and the ineffective portion of changes in fair value of designated hedges. See “Risk Management, Financing and Other” section of this MD&A for details.
(6)	Corporate acquisition represents the total consideration for the transaction, including working capital assumed.
(7)	Excludes volumes from Harvest’s equity investment in the Deep Basin Partnership.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Commodity Price Environment

	Three Months Ended June 30				Six Months Ended June 30
	2016	2015	Change		2016	2015	Change
West Texas Intermediate ("WTI") crude oil (US$/bbl)	45.59	57.94	(21%	)	39.52	53.29	(26%	)
West Texas Intermediate crude oil ($/bbl)	58.75	71.21	(17%	)	52.55	65.79	(20%	)
Edmonton Light Sweet crude oil ("EDM") ($/bbl)	54.64	67.75	(19%	)	47.74	59.85	(20%	)
Western Canadian Select ("WCS") crude oil ($/bbl)	41.58	57.07	(27%	)	34.10	49.58	(31%	)
AECO natural gas daily ($/mcf)	1.40	2.65	(47%	)	1.62	2.70	(40%	)
U.S. / Canadian dollar exchange rate	0.776	0.814	(5%	)	0.752	0.810	(7%	)
Differential Benchmarks
EDM differential to WTI ($/bbl)	4.11	3.52	17%		4.81	5.94	(19%	)
EDM differential as a % of WTI	7.0%	4.9%	43%		9.2%	9.0%	2%
WCS differential to WTI ($/bbl)	17.17	14.20	21%		18.45	16.21	14%
WCS differential as a % of WTI	29.2%	19.9%	47%		35.1%	24.6%	43%

The average WTI benchmark price decreased 21% and26%,respectivelyforsecondquarterandsixmonthsendedJune30,2016as compared to the same period in 2015. The average Edmonton Light Sweet crude oil price (“Edmonton Light”) decreased 19% and 20%, respectively, in the second quarter and firstsixmonthsended2016 compared to 2015. The decrease in Edmonton Light for the second quarter isdue to the decrease in the WTI price and the widening of the Edmonton Light differential, partially offset by the strengthening of the U.S. dollar against the Canadian dollar. The decrease in Edmonton Light for the firstsixmonthsisdue to the decrease in the WTI price, partially offset by the narrowing of the Edmonton Light differential while the U.S. dollar strengthened against the Canadian dollar.

Heavy oil differentials fluctuate based on a combination of factors including the level of heavy oil production and inventories, pipeline and rail capacity to deliver heavy crude to U.S. and offshore markets and the seasonal demand for heavy oil. The 27% and 31% decreases in the WCS price for the second quarter and six months ended June 30, 2016, respectively, as compared to the same period in 2015 was mainly the result of the decrease in the WTI price, the widening of the WCS differential to WTI partially offset by the strengthening of the U.S. dollar against the Canadian dollar.

North American natural gas prices continued to weaken during the second quarter and first six months of 2016. Harvest’s realized natural gas price is referenced to the AECO hub, which decreased 47% and 40%, respectively, in the second quarter and first six months of 2016 when compared to the same period in 2015.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Realized Commodity Prices

	Three Months Ended June 30				Six Months Ended June 30
	2016	2015	Change		2016	2015	Change
Light to medium oil ($/bbl)	46.35	58.68	(21%	)	39.79	51.75	(23%	)
Heavy oil prior to hedging($/bbl)	39.51	53.22	(26%	)	32.09	46.39	(31%	)
Natural gas liquids ($/bbl)	27.76	33.45	(17%	)	24.89	32.12	(23%	)
Natural gas prior to hedging($/mcf)	1.17	2.54	(54%	)	1.45	2.67	(46%	)
Average realized price prior to hedging ($/boe)(1)	26.50	37.85	(30%	)	23.58	34.79	(32%	)
Heavy oil after hedging ($/bbl)(2)	39.15	51.87	(25%	)	31.91	45.71	(30%	)
Natural gas after hedging ($/mcf)(2)	1.17	2.61	(55%	)	1.45	2.74	(47%	)
Average realized price after hedging ($/boe)(1)(2)	26.40	37.65	(30%	)	23.53	34.77	(32%	)

(1)	Inclusive of sulphur revenue.
(2)	Inclusive of the realized gains (losses) from contracts designated as hedges. Foreign exchange swaps and power contracts are excluded from the realized price.

Harvest’s realized prices prior to any hedging activity for light to medium oil generally trends with the Edmonton Light benchmark price. Harvest’s realized prices prior to any hedging activity for heavy oil are a function of both the WCS and Edmonton Light benchmarks due to a portion of our heavy oil volumes being sold based on a discount to the Edmonton Light benchmark. For the second quarter and first six months of 2016, the period-over-period variances and movements of light to medium oil and heavy oil were relatively consistent with the changes in their related benchmarks.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Harvest’s realized prices prior to any hedging activity for natural gas generally trend with the AECO benchmark prices. For the second quarter and first six months of 2016, the period-over-period variances and movements of natural gas price prior to hedging were relatively consistent with the changes in its benchmark.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Realized natural gas liquids prices decreased by 17% and 23% for the second quarter and six months ended June 30, 2016 as compared to the same period in 2015. The decreases are relatively consistent with the decrease in oil prices.

In order to partially mitigate the risk of fluctuating cash flows due to natural gas and heavy oil pricing volatility, Harvest will periodically enter into WCS and AECO derivative contracts. During the first six months of 2015 Harvest had AECO derivative contracts in place for a portion of its production, however none were in place in the first six months of 2016. During the second quarter of 2015 and 2016 Harvest had WCS derivative contracts in place for a portion of its production.

Please see “Cash Flow Risk Management” section in this MD&A for further discussion with respect to the cash flow risk management program.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Sales Volumes

	Three Months Ended June 30
	2016		2015
					% Volume
	Volume	Weighting	Volume	Weighting	Change
Light to medium oil (bbl/d)	6,604	19%	8,695	21%	(24%	)
Heavy oil (bbl/d)	9,821	29%	11,969	29%	(18%	)
Natural gas liquids (bbl/d)	3,734	11%	3,779	9%	(1%	)
Total liquids (bbl/d)	20,159	59%	24,443	59%	(18%	)
Natural gas (mcf/d)	85,688	41%	103,639	41%	(17%	)
Total oil equivalent (boe/d)	34,440	100%	41,716	100%	(17%	)

	Six Months Ended June 30
	2016		2015
					% Volume
	Volume	Weighting	Volume	Weighting	Change
Light to medium oil (bbl/d)	7,013	20%	9,260	22%	(24%	)
Heavy oil (bbl/d)	9,951	28%	12,013	28%	(17%	)
Natural gas liquids (bbl/d)	3,772	11%	4,004	9%	(6%	)
Total liquids (bbl/d)	20,736	59%	25,277	59%	(18%	)
Natural gas (mcf/d)	89,861	41%	104,757	41%	(14%	)
Total oil equivalent (boe/d)	35,713	100%	42,737	100%	(16%	)

Harvest’s average daily sales of light to medium oil decreased 24% in the second quarter of 2016, as compared to the same period in 2015. The decrease was mainly due to the disposition of non-core properties, natural declines, and reflect a greatly reduced drilling program in 2016.

Heavy oil sales for the second quarter of 2016 decreased 18% as compared to the same period in 2015 mainly due to non-core asset dispositions, natural declines, and reflect a greatly reduced drilling program in 2016.  

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Natural gas sales during the second quarter of 2016 decreased 17%, as compared to the same period in 2015. The decrease was mainly a result of disposition of assets to the Deep Basin Partnership during the fourth quarter of 2015, natural declines and reflect a greatly reduced drilling program in 2016.

Natural gas liquids sales for the second quarter of 2016 decreased by 1% from the same period in 2015 due to natural declines partially offset by less third party facility constraints.

Revenues

Sales Revenue by Product

	Three Months Ended June 30						Six Months Ended June 30
	2016		2015		Change		2016		2015		Change
Light to medium oil sales	27.9		46.4		(40%	)	50.8		86.7		(41%	)
Heavy oil sales after hedging(1)	35.0		56.5		(38%	)	57.8		99.4		(42%	)
Natural gas sales after hedging(1)	9.1		24.7		(63%	)	23.8		51.9		(54%	)
Natural gas liquids sales	9.4		11.5		(18%	)	17.1		23.3		(27%	)
Other(2)	1.4		3.9		(64%	)	3.5		8.1		(57%	)
Petroleum and natural gas sales	82.8		143.0		(42%	)	153.0		269.4		(43%	)
Royalties	(10.1	)	(12.2	)	(17%	)	(15.9	)	(25.3	)	(37%	)
Revenues	72.7		130.8		(44%	)	137.1		244.1		(44%	)

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

Harvest’s revenue is subject to changes in sales volumes, commodity prices, currency exchange rates and hedging activities. Total petroleum and natural gas sales decreased in the second quarter and first six months of 2016 as compared to 2015, mainly due to the decrease in sales volumes and the decrease in the realized prices.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Sulphur revenue represented $1.3 million of the total in other revenues for the second quarter of 2016 (2015 -$3.9 million) and $3.5 million for the first six months of 2016 (2015 - $7.6 million).

Revenue by Product Type as % of Total Revenue

	Three Months Ended June 30		Six Months Ended June 30
	2016	2015	2016	2015
Light to medium oil sales	34%	32%	33%	32%
Heavy oil sales after hedging	42%	40%	38%	37%
Natural gas sales after hedging	11%	17%	16%	19%
Natural gas liquids sales	11%	8%	11%	9%
Other	2%	3%	2%	3%
Total Sales Revenue	100%	100%	100%	100%

Although Harvest’s product mix on a volumetric basis is slightly weighted heavier towards crude oil and natural gas liquids than natural gas, revenue contribution is more heavily weighted to crude oil and liquids as shown by the graphs above. Compared to the prior year period, revenue contributions by product have remained relatively consistent year over year.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

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 Crown royalties are based on various sliding scales dependent on incentives, production volumes and commodity prices.

For the second quarter ended and six months ended June 30, 2016, royalties as a percentage of gross revenue averaged 12.2% and 10.4% respectively (2015 –8.5% and 9.4%) . The increase in royalties as a percentage of gross revenue was mainly due to lower gas costs allowance in the current periods partially offset by lower commodity prices.

In January of 2016, the provincial government of Alberta announced the key highlights of a proposed Modernized Royalty Framework (“MRF”) that will be effective on January 1, 2017 based on the royalty review panels recommendations. The highlights include providing royalty incentives for efficient development of conventional crude oil, natural gas and natural gas liquids resources, no changes to the royalty structure of wells drilled prior to 2017 for a period of ten years from the enactment, the replacement of royalty credits/holidays on conventional wells by a revenue minus cost framework with a post-payout royalty rate based on commodity prices, the reduction of royalty rates for mature wells and a neutral internal rate of return for any given play compared to the current royalty framework.

Details of these programs were released simultaneously with the finalization of the MRF, on April 21, 2016. More specific information will be provided by the provincial government in the coming months to help oil and natural gas producers better understand the economics of investments in Alberta. The MRF structure consists of three stages during the life cycle of a well; pre-payout, post payout, and post payout mature well.

The royalty formulas are price sensitive and product specific. The actual royalty rate is the sum of a price component and a quantity adjustment component that applies when monthly production from the well is below the Maturity Threshold, equivalent of 40 barrels of oil equivalent per day. The royalty rate has a minimum of 5% and a maximum of 40%.

In July 2016, the provincial government of Alberta announced further details regarding the MRF and introduced two royalty programs meant to encourage companies to develop emerging high-risk plays and enhance production from existing pools.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Operating and Transportation Expenses

	Three Months Ended June 30
	2016	$/boe	2015	$/boe	$/boe Change
Power and purchased energy	8.7	2.78	14.4	3.79	(1.01	)
Processing and other fees	9.2	2.95	8.6	2.27	0.68
Lease rentals and property tax	6.1	1.94	8.0	2.11	(0.17	)
Repairs and maintenance	6.4	2.05	8.7	2.29	(0.24	)
Labour - internal	5.0	1.59	6.1	1.61	(0.02	)
Chemicals	2.1	0.67	3.6	0.95	(0.28	)
Labour - contract	2.7	0.86	3.3	0.87	(0.01	)
Well servicing	2.6	0.82	5.1	1.34	(0.52	)
Trucking	1.1	0.36	2.2	0.58	(0.22	)
Other(1)	0.3	0.09	5.6	1.48	(1.39	)
Total operating expenses	44.2	14.11	65.6	17.29	(3.18	)
Transportation and marketing	1.0	0.32	1.7	0.45	(0.13	)

⁽¹⁾ Other operating expenses include EH&S $1.3 million (2015 – $2.2 million), insurance, overhead and net impact of accruals adjustments.

	Six Months Ended June 30
	2016		$/boe		2015	$/boe	$/boe Change
Power and purchased energy	18.8		2.89		28.1	3.63	(0.74	)
Processing and other fees	17.3		2.67		17.5	2.26	0.41
Lease rentals and property tax	14.9		2.29		16.3	2.11	0.18
Repairs and maintenance	13.3		2.05		21.4	2.77	(0.72	)
Labour - internal	11.1		1.71		15.3	1.98	(0.27	)
Chemicals	7.9		1.21		11.1	1.43	(0.22	)
Labour - contract	5.5		0.85		6.7	0.87	(0.02	)
Well servicing	5.4		0.83		13.0	1.68	(0.85	)
Trucking	2.6		0.40		4.3	0.55	(0.15	)
Other(1)	(5.9	)	(0.91	)	4.3	0.56	(1.47	)
Total operating expenses	90.9		13.99		138.0	17.84	(3.85	)
Transportation and marketing	2.4		0.36		2.9	0.38	(0.02	)

⁽¹⁾ Other operating expenses include EH&S $2.7 million (2015 – $4.5 million), insurance, overhead and net impact of accruals adjustments.

Operating expenses for the second quarter and first six months of 2016 decreased by $21.4 million and $47.1 million, respectively, compared to the same periods in 2015. The decreases were mainly due to overall lower activity levels which have resulted in a decrease in the cost of power, reduced levels of well servicing and repairs and maintenance activity, chemicals, reductions in labour and asset dispositions. Operating expenses on a per barrel basis decreased by 18% to $14.11 per barrel and 22% to $13.99 per barrel for second quarter and first six months of 2016, respectively when compared to the same periods in 2015, mainly due to lower activity levels and spending, partially offset by the lower sales volumes.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Three Months Ended June 30					Six Months Ended June 30
($/boe)	2016	2015		Change		2016	2015	Change
Power and purchased energy costs	2.78	3.79		(1.01	)	2.89	3.63	(0.74	)
Realized losses (gains) on electricity    derivative contracts	0.12	(0.20	)	0.32		0.13	0.07	0.06
Net power and purchased energy costs	2.90	3.59		(0.69	)	3.02	3.70	(0.68	)
Alberta Power Pool electricity price ($/MWh)	14.99	57.25		(42.26	)	16.54	43.20	(26.66	)

Power and purchased energy costs, comprised primarily of electric power costs, represented approximately 20% and 21% (2015 – 22% and 20%) of total operating expenses for the second quarter and first six months of 2016, respectively. Power and purchased energy costs per boe were lower in the second quarter and first six months of 2016 as compared to 2015 primarily due to the lower average Alberta electricity price.

Transportation and marketing expenses relate primarily to the cost of trucking crude oil to pipeline or rail receipt points. Transportation and marketing expenses in the second quarter and first six months of 2016 remained relatively consistent compared to the same periods in 2015.

Operating Netback⁽¹⁾

	Three Months Ended June 30						Six Months Ended June 30
($/boe)	2016		2015		Change		2016		2015		Change
Petroleum and natural gas sales prior to hedging(2)	26.50		37.85		(11.35	)	23.58		34.79		(11.21	)
Royalties	(3.22	)	(3.19	)	(0.03	)	(2.45	)	(3.26	)	0.81
Operating expenses	(14.11	)	(17.29	)	3.18		(13.99	)	(17.84	)	3.85
Transportation and marketing	(0.32	)	(0.45	)	0.13		(0.36	)	(0.38	)	0.02
Operating netback prior to hedging(1)	8.85		16.92		(8.07	)	6.78		13.31		(6.53	)
Hedging loss(3)	(0.22	)	(0.04	)	(0.18	)	(0.18	)	(0.13	)	(0.05	)
Operating netback after hedging(1)	8.63		16.88		(8.25	)	6.60		13.18		(6.58	)

(1)	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.
(2)	Excludes miscellaneous income not related to oil and gas production
(3)	Includes the settlement amounts for natural gas, crude oil and power contracts.

For the second quarter and six months ended June 30, 2016 netback prior to hedging were $8.85 per boe and $6.78 per boe, respectively, representing decreases of 48 percent and 49 percent compared to the same periods in 2015.

For the second quarter and six months ended June 30, 2016 netback after hedging were $8.63 per boe and $6.60 per boe, respectively, representing decreases of 49 percent and 50 percent compared to the same periods in 2015.

The decrease in period was mainly due to lower realized sale prices, partially offset by reduced operating expenses.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

General and Administrative (“G&A”) Expenses

	Three Months Ended June 30						Six Months Ended June 30
��	2016		2015		Change		2016		2015		Change
Gross G&A expenses	14.0		16.8		(17%	)	29.2		37.4		(22%	)
Capitalized G&A	(0.7	)	(3.9	)	82%		(1.2	)	(5.5	)	78%
Net G&A expenses	13.3		12.9		3%		28.0		31.9		(12%	)
Net G&A expenses ($/boe )	4.24		3.39		25%		4.32		4.12		5%

For the second quarter and first six months ended June 30, 2016 G&A expenses net of capitalized G&A increased $0.4 million and decreased $3.8 million respectively, while gross G&A expenses decreased $2.8 million and $8.1 million respectively, when compared to the same period in the prior year. The decrease in the gross G&A expenses from the same periods in the prior year were mainly due to comparative lower staffing levels, lower bonus and LTI accruals, decreases in employee benefits expenses, partially offset by increases due to severance charge related to staff layoff completed during the first six months of 2016. The reduction in capitalized G&A is mainly related to reduced capital spending in 2016.

On a per boe basis, G&A expenses increased $0.85 and $0.20 in the second quarter and first six months of 2016, from the same period in the prior year mainly due to lower sales volumes in the current year. Harvest does not have a stock option program, however there is a long-term incentive program which is a cash settled plan that has been included in the G&A expense.

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

	Three Months Ended June 30		Six Months Ended June 30
	2016	2015	2016	2015
DD&A	66.6	98.8	141.3	197.1
DD&A ($/boe)	21.24	26.02	21.73	25.48

DD&A expense for the second quarter and first six months of 2016 decreased by $32.2 million and $55.8 million, respectively as compared to the same period in 2015, mainly due to lower sales volumes and the impact of a lower DD&A rate due to impairment charges recorded during fiscal 2015.

Impairment Expense
For the second quarter and first six months of 2016, Harvest recognized no impairment loss (2015 – $70.7 million and $94.2 million, respectively) against PP&E relating to the cash generating units (“CGU”). At June 30, 2016, Harvest reviewed and adjusted its CGUs as a result of the Company’s ongoing divestiture activity and corporate re-organization. CGU’s were aggregated due to similarities in operations, management and monitoring, product composition and cash flows.

Acquisitions & Dispositions
On June 30, 2016, Harvest closed the disposition of all of its oil and gas assets in Saskatchewan for net proceeds of $62.3 million. Together with other insignificant dispositions of Upstream assets, Harvest recognized a gain of $17.7 million and $17.3 million for the three and six months ended June 30, 2016, respectively (2015 – losses of $5.8 million and $5.3 million), relating to the de-recognition of PP&E, E&E, goodwill and decommissioning and environmental liabilities.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Subsequent to June 30, 2016, Harvest entered into a purchase and sale agreement to sell certain non-core oil and gas assets in Southern Alberta for approximately $5.8 million in cash proceeds, net of any customary closing adjustments. The sale is expected to close during the third quarter of 2016.

Capital Asset Additions

	Three Months Ended June 30			Six Months Ended June 30
	2016		2015	2016		2015
Drilling and completion	(0.7	)	32.2	(0.9	)	70.2
Well equipment, pipelines and facilities	0.4		9.7	2.8		25.3
Land and seismic	0.4		0.9	0.4		2.1
Corporate	—		1.2	(0.4	)	3.0
Other	0.6		4.4	0.9		4.4
Total additions excluding acquisitions	0.7		48.4	2.8		105.0

Total capital additions were lower for the second quarter and first six months of 2016 compared to 2015 mainly due to reduced capital activity for the current year in response to a low commodity price environment. Harvest’s capital expenditures in the second quarter and first six months of 2016 related to well equipment, pipelines and facilities.

The following table summarizes the wells drilled in our core growth areas and the related drilling and completion costs incurred in the period. A well is recorded in the table as having being drilled after it has been rig-released, however related drilling costs may be incurred in a period before a well has been spud (including survey, lease acquisition and construction costs) and related completion and tie-in costs may be incurred in a period afterwards, depending on the timing of the completion work.

	Three Months Ended June 30					Six Months Ended June 30
				Drilling and					Drilling and
Area	Gross	Net		completion		Gross	Net		completion
Deep Basin	—	—	$	-		1.0	0.3	$	(1.3	)
Other areas	—	—		(0.7	)	—	—		0.4
Total	—	—	$	(0.7	)	1.0	0.3	$	(0.9	)

During the second quarter of 2016 Harvest did not drill any wells. During the first 6 months of 2016 Harvest participated in one partner-operated horizontal multi-stage fractured well to develop the liquids-rich Falher gas formations.

During the second quarter and six months ended June 30, 2016, Harvest’s net undeveloped land additions were 5,302 acres and 10,868 acres respectively (2015 – 18,206 acres and 38,544 acres).

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Decommissioning Liabilities
Harvest’s Upstream decommissioning liabilities at June 30, 2016 was $775.5 million (December 31, 2015 – $796.6 million) for future remediation, abandonment, and reclamation of Harvest’s oil and gas properties. The total of the decommissioning liabilities are based on management’s best estimate of costs to remediate, reclaim, and abandon wells and facilities. The decrease in balance as at June 30, 2016 is mainly due disposition of properties, partially offset by revisions to the estimate as a result of changes in the Bank of Canada long term interest rates. 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 the decommissioning liabilities.

Investments in Joint Ventures
Harvest has equity investments in Deep Basin Partnership (“DBP”) and HK MS Partnership (“HKMS”) joint ventures with KERR Canada Co. Ltd. (“KERR”) which are accounted for as equity investments. Harvest derives its income or loss from its investments based upon Harvest’s share in the change of the net assets of the joint venture. Harvest’s share of the change in the net assets does not directly correspond to its ownership interest because of contractual preference rights to KERR and changes based on contributions made by either party during the year. For the second quarter and six months ended June 30, 2016, Harvest recognized a loss of $10.6 million and $29.1 million (2015 – $10.1 million and $16.0 million) from its investment in the DBP and HKMS joint ventures.

Below is an overview of operational and financial highlights of the DBP and HKMS joint ventures for the second quarter and six months ended June 30, 2016. Unless otherwise noted the following discussion relates to 100% of the joint venture results and not based on Harvest ownership share.

Deep Basin Partnership
DBP was established for the purposes of exploring, developing and producing from certain oil and gas properties in the Deep Basin area in Northwest Alberta. During the year ended 2015 and six month ended June 30, 2016 Harvest made various contributions to the DBP that resulted in increase in its ownership percentage as reflected in the table below.

	June 30,	March 31,	December 31,	September 30,	June 30,	March 31,	December 31,
	2016	2016	2015	2015	2015	2015	2014
Harvest's ownership interest	82.00%	81.98%	81.71%	81.05%	79.30%	77.81%	77.81%
KERR's ownership interest	18.00%	18.02%	18.29%	18.95%	20.70%	22.19%	22.19%
Total	100.00%	100.00%	100.00%	100.00%	100.00%	100.00%	100.00%

As at June 30, 2016, the fair value of Harvest’s top-up obligation to KERR, related to a minimum rate of return commitment was estimated as $12.0 million (December 31, 2015 - $2.0 million).

At June 30, 2016, Harvest received a total of $6.0 million (December 31, 2015 - $4.3 million) in distributions from the DBP from inception of the joint venture.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Three Months Ended June 30				Six Months Ended June 30
	2016	2015	Change		2016	2015	Change
Natural gas (mcf/d)	30,623	22,054	39%		28,078	14,742	90%
Natural gas liquids (bbl/d)	1,097	1,222	(10%	)	1,280	786	63%
Light to medium oil (bbl/d)	2	1	100%		2	1	100%
Total (boe/d)	6,204	4,898	27%		5,962	3,244	84%
Harvest's share(1)	5,087	3,884	31%		4,888	2,561	91%

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

Sales volumes for the second quarter and six months ended June 30, 2016 increased by 1,306 boe/d and 2,718 boe/d respectively, as compared to the same period in 2015. The increases were primarily due to new wells being brought online through the HKMS natural gas processing plant that commenced operations in early 2015 and additional assets contributed on October 1, 2015 by Harvest, partially offset by production curtailments due to third party restrictions.

	Three Months Ended June 30						Six Months Ended June 30
	2016		2015		Change		2016		2015		Change
Revenues	6.6		9.6		(31%	)	14.2		12.1		17%
Operating expenses and Other	(8.4	)	(8.0	)	(5%	)	(15.5	)	(11.1	)	(40%	)
Depletion, depreciation and amortization	(10.3	)	(13.6	)	24%		(19.7	)	(17.9	)	(10%	)
Finance costs	(0.7	)	(0.7	)	0%		(1.4	)	(1.4	)	0%
Impairment	-		-		-		(1.4	)	-		-
Losses on disposition of assets	-		-		-		(9.8	)	-		-
Net loss(1)	(12.8	)	(12.7	)	(1%	)	(33.6	)	(18.3	)	(84%	)

⁽¹⁾ Balances represent 100% share of the DBP.

The lower sales revenues in the second quarter ended June 30, 2016 reflect the lower commodity prices, partially offset by higher volumes, and lower royalties compared to the same period in the prior year. The higher sales revenues in the first six months of 2016 reflect the higher sales volumes and lower royalties, partially offset by lower commodity prices compared to the same period in 2015.

Operating expenses and other expenses for the second quarter and first six months of 2016 were $14.91 per boe and $14.29 per boe, respectively, decreases of $3.14 per boe and $4.64 per boe from the same periods in 2015. The decreases from 2015 was mainly due to the higher sales volume being processed through the HKMS natural gas processing plant resulting in lower operating expense on a boe basis.

Depletion for the second quarter and six months ended June 30, 2016 were $18.21 per boe and $18.17 per boe, respectively (2015 – $30.57 per boe and $30.51 per boe). The decreases from 2015 was mainly due to the impact of an impairment charge recorded during the fourth quarter of 2015 and additional proved reserves recognized in the fourth quarter of 2015 partially offset by higher volumes.

For the six months of 2016, the DBP recognized an impairment loss of $1.4 million relating to a final statement of adjustments for a corporate acquisition completed in the fourth quarter of 2015. As the partnerships property, plant and equipment (PP&E) assets were impaired as at December 31, 2015 the additions to PP&E as a result of the statement of adjustment were followed through as an expense in the first quarter of 2016.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

On January 15, 2016 the DBP closed an asset exchange whereby the carrying value of assets given up exceeded the fair value of assets received based on the booked reserves associated with the properties exchanged. This transaction resulted in a loss on disposition of PP&E of $9.8 million.

	Three Months Ended June 30		Six Months Ended June 30
	2016	2015	2016	2015
Drilling and completion	0.8	1.1	7.0	41.1
Well equipment, pipelines and facilities	0.2	0.7	3.2	14.8
Land and seismic	-	-	0.1	-
Total(1)	1.0	1.8	10.3	55.9

⁽¹⁾ Balances represent 100% share of the DBP.

Capital asset additions were $1.0 million and $10.3 million in the second quarter and six months ended June 30, 2016, mainly related to drilling, completion and tie-in of wells. During the first six months of 2016, DBP drilled 3 gross (2.5 net) wells.

HKMS Partnership
During the year ended 2015 and first six months ended June 30, 2016 Harvest made various contributions to the HKMS that resulted in increase in its ownership percentage as reflected in the table below.

	June 30,	March 31,	December 31, September 30,		June 30,	March 31,	December 31,
	2016	2016	2015	2015	2015	2015	2014
Harvest's ownership	70.19%	70.15%	69.93%	69.16%	68.69%	49.49%	47.01%
KERR's ownership interest	29.81%	29.85%	30.07%	30.84%	31.31%	50.51%	52.99%
Total	100.00%	100.00%	100.00%	100.00%	100.00%	100.00%	100.00%

At June 30, 2016, Harvest received a total of $15.5 million (December 31, 2015 - $7.7 million) in distributions from the HKMS from inception of the joint venture.

	Three Months Ended June 30						Six Months Ended June 30
	2016		2015		Change		2016		2015		Change
Revenues	6.1		6.4		(5%	)	12.2		7.8		56%
Operating expenses and Other	(0.5	)	(0.5	)	0%		(0.9	)	(1.0	)	10%
Depreciation and amortization	(0.9	)	(0.8	)	(13%	)	(1.7	)	(1.4	)	(21%	)
Finance costs	(4.9	)	(4.3	)	(14%	)	(9.8	)	(5.1	)	(92%	)
Net (loss) income(1)	(0.2	)	0.8		(125%	)	(0.2	)	0.3		(167%	)

⁽¹⁾ Balances represent 100% share of the HKMS.

The Gas Processing Agreement between the HKMS and DBP ensures that HKMS receives an 18% internal rate of return on capital deployed over the term of the contract. In order to guarantee this return, DBP is required to provide HKMS with a minimum monthly capital fee that is currently $1.9 million a month. This capital fee is accounted for as revenue for HKMS and an operating expense for the DBP. In addition HKMS also generates revenue from charging an operating fee to recover operating expenses incurred. For the second quarter and six months ended June 30, 2016 the partnership generated revenues of $6.1 million and $12.2 million, respectively (2015 – $6.4 million and $7.8 million).

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Operating expenses of the facility are recovered through charging an operating fee to the producers. For the second quarter and six months ended June 30, 2016 the partnership operating expense were $0.5 million and $0.9 million, respectively (2015 – $0.5 million and $1.0 million).

Depreciation has been calculated on a straight-line basis over a 30 year useful life. Based on the capital expenditures incurred to date, the depreciation on a monthly basis is approximately $0.3 million per month. For the second quarter and six months ended June 30, 2016 the partnership depreciation expense were $0.9 million and $1.7 million, respectively (2015 – $0.8 million and $1.4 million).

Finance costs mainly represent an accounting charge resulting from the Partner’s contributions being classified as liabilities, as a result of the Gas Processing Agreement guaranteed returns. The finance costs represent the 18% rate of return on the partner’s contributions. For the second quarter and six months ended June 30, 2016 the partnership finance costs was $4.9 million and $9.8 million, respectively (2015 – $4.3 million and $5.1 million).

See note 8 of the June 30, 2016 condensed interim consolidated financial statements for discussion of the accounting implications of these joint ventures.

BLACKGOLD OIL SANDS

Pre-operating Results

	Three Months Ended June 30				Six Months Ended June 30
	2016		2015		2016		2015
Expenses
Pre-operating	2.0		4.3		5.8		5.4
General and administrative	0.5		1.4		1.1		1.4
Depreciation and amortization	0.2		0.1		0.3		0.2
Pre-Operating loss(1)	(2.7	)	(5.8	)	(7.2	)	(7.0	)

⁽¹⁾ This is an additional GAAP measure; please refer to “Additional GAAP Measures” in this MD&A.

As the central processing facility (“CPF”) was substantially completed during the first quarter of 2015, the operating expenses that were previously capitalized to property plant and equipment are now expensed on the income statement. For the second quarter and six months ended June 30, 2016, Harvest recognized an operating loss of $2.7 million and $7.2 million (2015 – $5.8 million and $7.0 million) respectively, mainly relating to labour, power, maintenance and general and administrative expenses.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Capital Asset Additions

	Three Months Ended June 30		Six Months Ended June 30
	2016	2015	2016	2015
Well equipment, pipelines and facilities	—	3.7	—	43.2
Pre-operating costs	—	0.1	—	7.1
Drilling and completion	0.1	—	0.1	0.4
Capitalized borrowing costs and other	—	—	0.1	13.9
Total BlackGold additions	0.1	3.8	0.2	64.6

During the second quarter and first six months of 2016, Harvest invested $0.1 million and $0.2 million, respectively (2015 –$3.8 million and $64.6 million).

Decommissioning Liabilities
Harvest’s BlackGold decommissioning liabilities at June 30, 2016 was $63.7 million (December 31, 2015 - $50.1 million) relating to the future remediation, abandonment, and reclamation of the steam assisted gravity drainage (“SAGD”) wells and CPF. The increase in balance as at June 30, 2016 is mainly due revisions to the estimate as a result of changes in the Bank of Canada long term interest rates. Please see 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 the decommissioning liabilities.

Project Development
Harvest has been developing its BlackGold oil sands CPF under the engineering, procurement and construction (“EPC”) contract. Initial drilling of 30 SAGD wells (15 well pairs) was completed by the end of 2012 and the majority of the well completion activities were completed by the end of 2014. More SAGD wells will be drilled in the future to compensate for the natural decline in production of the initial well pairs and maintain the Phase 1 production capacity of 10,000 bbl/d. During the first quarter of 2015 construction had been substantially completed, including the building of the CPF plant site, well pads, and connecting pipelines. Several systems have since been commissioned and others will be progressed slowly within a limited budget. The decision to complete commissioning of the CPF and commence steam injection depends on a number of factors including the bitumen price environment.

Harvest has recorded $1,080.6 million of costs on the entire project since acquiring the BlackGold assets in 2010. This $1,080.6 million includes certain Phase 2 pre-investment which is expected to improve the capital efficiency over the project lifecycle. Under the EPC contract, $94.9 million of the EPC costs will be paid in equal installments, without interest, over 10 years. Payments commenced during the second quarter of 2015 with two payments made on April 30, 2015. Harvest withheld the third deferred payment due April 30, 2016 as it is in process of conducting a comprehensive audit of costs and expenses incurred by the Contractor in connection with the work. The liability is considered a financial liability and is initially recorded at fair value, which is estimated as the present value of all future cash payments discounted using the prevailing market rate of interest for similar instruments. As at June 30, 2016, Harvest recognized a liability of $63.7 million (December 31, 2015 - $62.0 million) using a discount rate of 5.5% (December 31, 2015 - 5.5%) .

As Harvest uses the unit of production method for depletion and the BlackGold assets currently have no production, no depletion on the BlackGold property, plant and equipment has been recorded. Minor depreciation has been recorded during the second quarter and first six months of 2016 on administrative assets.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

RISK MANAGEMENT, FINANCING AND OTHER

Cash Flow Risk Management
The Company at times enters into natural gas, crude oil, electricity and foreign exchange contracts to reduce the volatility of cash flows from some of its forecast sales and purchases, and when allowable, will designate these contracts as cash flow hedges. The following is a summary of Harvest’s derivative contracts outstanding at June 30, 2016:

Contracts Designated as Hedges
					Fair value of
Contract Quantity	Type of Contract	Term			Liability
2,800 bbl/day	WCS price swap	July - Dec 2016	US$33.50/bbl	$	(1.3	)

Contracts Not Designated as Hedges
						Fair Value of
Contract Quantity	Type of Contract	Term/Expiry		Contract Price		Assets
12 MW	AESO power swap	July - Dec 2016	$	34.63/MWh	$	0.1
US$390 million	Foreign exchange swap	July 2016	$	1.2825 Cdn/US		3.5
					$	3.6

Harvest has entered into U.S. dollar currency swap transactions related to a LIBOR borrowing, which results in a reduction of interest expense paid on Harvest’s borrowings related to its credit facility. As a result of these transactions, Harvest’s effective interest rate for borrowings under the credit facility for the three and six months ended June 30, 2016 was 1.6% (2015 – 2.1% and 2.4%, respectively).

	Three Months Ended June 30
	2016								2015
Realized (gains) losses			Crude			Natural	Top-Up				Crude		Natural
recognized in:	Power		Oil	Currency		Gas	Obligation	Total	Power		Oil	Currency	Gas		Total
Revenues	—		0.3	—		—	—	0.3	—		1.4	—	(0.7	)	0.7
Derivative contract (gains) losses	0.4		—	—		—	—	0.4	(0.9	)	—	0.2	—		(0.7	)
Unrealized (gains) lossesrecognized in:
OCI, before tax	—		1.6	—		—	—	1.6	—		3.4	—	(0.8	)	2.6
Derivative contract (gains) losses	(0.3	)	—	(4.4	)	—	10.3	5.6	(3.7	)	—	—	—		(3.7	)

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Six Months Ended June 30
	2016								2015
Realized (gains) losses			Crude			Natural	Top-Up				Crude		Natural
recognized in:	Power		Oil	Currency		Gas	Obligation	Total	Power		Oil	Currency	Gas		Total
Revenues	—		0.3	—		—	—	0.3	—		1.4		(1.2	)	0.2
Derivative contract (gains) losses	0.8		—	—		—	—	0.8	0.5		—	0.2	—		0.7
Unrealized (gains) lossesrecognized in:
OCI, before tax	—		1.6	—		—	—	1.6	—		3.4	—	(0.8	)	2.6
Derivative contract (gains) losses	(0.1	)	—	(3.5	)	—	10.0	6.4	(2.6	)	—	—	—		(2.6	)

Finance Costs

	Three Months Ended June 30		Six Months Ended June 30
	2016	2015	2016	2015
Credit facility(1)	4.4	7.8	9.4	13.5
6⅞% senior notes	10.9	11.3	23.5	22.5
2⅛% senior notes(1)	5.7	5.5	11.8	11.0
2⅓% senior notes(1)	0.3	-	0.3	-
Related party loans	9.3	7.4	18.0	13.1
Amortization of deferred finance charges and other	0.7	0.5	1.3	1.0
Interest and other financing charges	31.3	32.5	64.3	61.1
Accretion of decommission and environmental remediation liabilities	4.9	4.7	9.8	9.4
Accretion of long-term liability	0.8	0.9	1.6	0.9
Less: capitalized interest	—	—	—	(9.7	)
Total finance costs	37.0	38.1	75.7	61.7

⁽¹⁾ Includes guarantee fee to KNOC.

Currency Exchange

	Three Months Ended June 30				Six Months Ended June 30
	2016		2015		2016		2015
Realized (gains) losses on foreign exchange	(18.4	)	0.3		(25.2	)	0.9
Unrealized (gains) losses on foreign exchange	13.0		(22.8	)	(105.7	)	116.1
Total (gains) losses on foreign exchange	(5.4	)	(22.5	)	(130.9	)	117.0

Currency exchange gains and losses are attributed to the changes in the value of the Canadian dollar relative to the U.S. dollar on the U.S. dollar denominated 6⅞%, 2⅛% and 2⅓% senior notes, the ANKOR and KNOC related party loan and on any U.S. dollar denominated monetary assets or liabilities. At June 30, 2016, the Canadian dollar had weakened compared to the US dollar as at March 31, 2016 resulting in an unrealized foreign exchange loss of $13.0 million for the second quarter of 2016 (2015 – $22.8 million gain). Harvest recognized a realized foreign exchange gain of $18.4 million for the second quarter of 2016 (2015 – $0.3 million loss) as a result of the settlement of U.S. dollar denominated transactions and $16.3 million of which relates to the debt exchange transaction. During the six months ending June 30, 2016, the Canadian dollar had strengthened compared to the US dollar as at December 31, 2015 resulting in an unrealized foreign exchange gain of $105.7 million (2015 – $116.1 million loss). Harvest recognized a realized foreign exchange gain of $25.2 million for the first six months of 2016 (2015 – $0.9 million loss) as a result of the settlement of U.S. dollar denominated transactions and $16.3 million of which relates to the debt exchange transaction.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Deferred Income Taxes
For the second quarter and six months ended June 30, 2016 Harvest did not record a deferred income tax recovery (2015 – $73.8 million and $124.3 million, respectively). Harvest’s deferred income tax asset will fluctuate during each accounting period to reflect changes in the temporary differences between the book value and tax basis of assets and liabilities. Currently, the principal sources of temporary differences relate to the Company’s property, plant and equipment, decommissioning liabilities and the unclaimed tax pools.

Related Party Transactions
The following provides a summary of the related party transactions between Harvest and KNOC for the quarter ended June 30, 2016:

Related Party Loans

Related			Interest			Carrying Value				Interest Payable
Party		Principal	Rate	Maturity Date		June 30, 2016		Dec 31, 2015		June 30, 2016		Dec 31, 2015
KNOC		US$171	5.91%	December 31, 2017	$	220.9	$	166.1	$	9.4	$	4.1
KNOC	$	200	5.30%	December 30, 2018		194.2		193.2		22.6		16.7
ANKOR		US$170	4.62%	October 2, 2017		219.6		235.3		18.7		14.6

						Interest expense
Related			Interest			Three months ended June 30				Six months ended June 30
Party		Principal	Rate	Maturity Date		2016		2015		2016		2015
KNOC		US$171	5.91%	December 31, 2017	$	3.3	$	1.6	$	5.7	$	1.5
KNOC	$	200	5.30%	December 30, 2018		3.5		3.4		6.9		6.8
ANKOR		US$170	4.62%	October 2, 2017		2.5		2.4		5.2		4.9

On June 30, 2016 Harvest entered into an US$184.8 million loan agreement with KNOC, due on October 2, 2017. The interest rate will be determined during the third quarter of 2016. Subsequent to June 30, 2016, Harvest drew down the US$184.8 million and used the proceeds to re-pay the US$170 million ANKOR loan, including accrued interest. ANKOR is a fully-owned subsidiary of KNOC. As a result of this transaction, all related party loans are with KNOC.

The related party loans are unsecured and the loan agreements contain no restrictive covenants.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Transactions
	Three Months Ended			Six Months Ended			Accounts Payable as at
	June 30			June 30			June 30	December 31
	2016	2015		2016	2015		2016	2015
G&A Expenses
KNOC(1)	0.1	(0.8	)	0.2	(2.6	)	0.8	0.8
Finance costs
KNOC(2)	1.9	1.1		4.2	2.2		1.4	3.5

(1)	Amounts relate to the payments to (reimbursement from) KNOC for secondee salaries.
(2)	Charges from KNOC for the irrevocable and unconditional guarantee they provided on Harvest’s 2⅛%, 2⅓% senior notes and the senior unsecured credit facility. A guarantee fee of 52 and 37 basis points per annum is charged by KNOC on the 2⅛% and 2⅓% senior notes, respectively and 37 basis points per annum on the credit facility.

The Company identifies its related party transactions by making inquiries of management and the Board of Directors, reviewing KNOC’s subsidiaries and associates, and performing a comprehensive search of transactions recorded in the accounting system. Material related party transactions require the Board of Directors’ approval. Also see note 8, “Investment in Joint Ventures” in the June 30, 2016 condensed interim consolidated financial statements for details of related party transactions with DBP and HKMS.

CAPITAL RESOURCES

The following table summarizes Harvest’s capital structure and provides the key financial ratios defined in the credit facility agreement.

	June 30, 2016		December 31, 2015
Credit facility(1)	891.6		926.6
6⅞% senior notes (US$282.5 million)(1)(2)	364.9		692.0
2⅛% senior notes (US$630 million)(1)(2)	813.8		871.9
2⅓% senior notes (US$195.8 million)(2)	252.9		—
Related party loans (US$341 million and CAD$200 million)(2)	640.5		601.4
	2,963.7		3,091.9
Shareholder's equity
386,078,649 common shares issued	(355.0	)	(275.3	)
	2,608.7		2,816.6

(1)	Excludes capitalized financing fees
(2)	Face value converted at the period end exchange rate
(3)	As at December 31, 2015, related party loans comprised of US$170 million from ANKOR, US$120 million from KNOC and $200 million from KNOC.

On June 16, 2016 Harvest completed an exchange of a significant portion of its 6⅞% senior notes due 2017 for new 2⅓% senior notes due 2021, at an exchange ratio of US$900 principal amount of the new 2⅓% senior notes for each US$1,000 principal amount of the old 6⅞% senior notes. US$217.5 million of the old 6⅞% senior notes was exchanged for US$195.8 million new 2⅓% senior notes. The extinguishment of the old 6⅞% senior notes resulted in a gain of $19.8 million and a realized foreign exchange gain of $16.3 million. The transaction provides significant saving to Harvest by reducing interest expense by US$9.9 million annually, as well as reduction in principal of US $21.7 million.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

During 2015, Harvest amended its $1 billion syndicated revolving credit facility and replaced it with a KNOC guaranteed $1.0 billion revolving credit facility that matures on April 30, 2017, with a syndicate of nine financial institutions. A guarantee fee of 0.37% per annum of the principal balance is payable to KNOC semi-annually.

Under the amended credit facility, applicable interest and fees are based on a margin pricing grid based on the Moody’s and S&P credit ratings of KNOC. The financial covenants under the previous credit facility were deleted and replaced with a new covenant: Total Debt to Capitalization ratio of 70% or less. At December 31, 2015, Harvest was in violation of the debt covenant and the carrying value of the credit facility, $923.8 million, was reclassified from long-term debt to a current liability. On February 5, 2016 Harvest’s syndicate banks consented to a waiver of this covenant for the duration of the term of the credit facility and the maturity date remains at April 30, 2017, and the credit facility was classified as current as at June 30, 2016.

LIQUIDITY

The Company’s liquidity needs are met through the following sources: cash generated from operations,proceeds from asset dispositions, joint arrangements, borrowings under the credit facility, related party loans, long-term debt issuances and capital injections by KNOC. Harvest’s primary uses of funds are operating expenses, capital expenditures, and interest and principal repayments on debt instruments.

Cash used in operating activities for the three months ended June 30, 2016 was $40.2 million (2015 – $44.4 million). The decrease in the second quarter of 2016 is mainly a result of reduced expenses and changes in working capital requirement partially offset by lower revenues. Cash used in operating activities for the six months ended June 30, 2016 was $39.9 million (2015 – $55.1 million). The decrease in the first six months of 2016 is mainly a result of reduced expenses and changes in working capital requirement partially offset by lower revenues.

Cash contributions from Harvest’s Upstream operations for the second quarter and the six months ended June 30, 2016 was $15.4 million and $16.2 million, respectively (2015 – $52.5 million and $71.7 million). The decrease in Upstream’s cash contribution for the second quarter and six months as compared to the same periods in 2015 is mainly due to the decreases in average realized prices and lower sales volumes, partially offset by lower expenses.

Harvest funded capital expenditures for the second quarter and six months ended June 30, 2016 of $0.7 million and $2.9 million, respectively (2015 – $53.2 million and $205.1 million) with the proceeds from property dispositions and borrowings under both the credit facility and KNOC subordinated loan.

Harvest net repayment to the credit facility was $5.9 million and $38.9 million during the second quarter and six month period ended June 30, 2016, respectively (2015 – $16.9 million and $266.4 million net drawings).

Harvest had a working capital deficiency of $993.3 million as at June 30, 2016, as compared to a $1,070.5 million deficiency at December 31, 2015, mainly due to the inclusion of the credit facility as current. Harvest anticipates engaging discussion with its syndicate banks to extend the maturity of the credit facility later in 2016. Harvest’s working capital is expected to fluctuate from time to time, and will be funded from cash flows from operations and borrowings from the credit facility managing the collection and payment of accounts receivables and accounts payables respectively and using the proceeds from possible sale of assets, as required.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Harvest ensures its liquidity through the management of its capital structure, seeking to balance the amount of debt and equity used to fund investment in each of our operating segments. Harvest evaluates its capital structure using the same financial covenant ratios as the ones that were externally imposed under the Company’s credit facility and the senior notes. The Company continually monitors its credit facility covenants and actively takes steps, such as reducing borrowings, increasing capitalization, amending or renegotiating covenants as and when required.

In response to the low commodity price environment, Harvest plans to constrain its capital expenditures in 2016, focusing on capital maintenance and regulatory activities. Harvest also continues to postpone first steam for the BlackGold project in response to the unfavourable heavy oil prices and will continually assess the commodity price environment to determine when to complete commissioning of the CPF and first steam injection.

Harvest is a significant subsidiary for KNOC in terms of production and reserves. KNOC has directly or indirectly invested and provided financial support to Harvest since 2009 and, as at the date of preparation of this MD&A, it is the Company’s expectation that such support will continue for at least next twelve months so that Harvest is able to continue as a going concern.

Contractual Obligations and Commitments
Harvest has recurring and ongoing contractual obligations and estimated commitments entered into in the normal course of operations. As at June 30, 2016, Harvest has the following significant contractual obligations and estimated commitments:

	Payments Due by Period
	1 year	2-3 years	4-5 years	After 5 years	Total
Debt repayments(1)	891.6	1,818.6	252.9	—	2,963.1
Debt interest payments(1)(2)	64.8	151.9	13.7	—	230.4
Purchase commitments(3)	22.0	21.0	19.0	60.4	122.4
Operating leases	6.4	14.1	16.3	31.2	68.0
Firm processing commitments	17.2	29.7	23.2	52.2	122.3
Firm transportation agreements	22.6	52.5	34.7	53.9	163.7
Employee benefits(4)	1.8	0.6	—	—	2.4
Decommissioning and environmental liabilities(5)	11.9	85.9	37.7	1,164.2	1,299.7
Total	1,038.3	2,174.3	397.5	1,361.9	4,972.0

(1)	Assumes constant foreign exchange rate.
(2)	Assumes interest rates as at June 30, 2016 will be applicable to future interest payments.
(3)	Relates to the BlackGold deferred payment under the EPC contract (see “BlackGold Oil Sands” section of this MD&A for details), and revised estimated capital costs for the Bellshill area (see “Impairment of Property, Plant & Equipment” section of this MD&A for details).
(4)	Relates to the long-term incentive plan payments.
(5)	Represents the undiscounted obligation by period.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Off Balance Sheet Arrangements
See “Investments in Joint Ventures” section in this MD&A and note 8, “Investment in Joint Ventures” in the June 30, 2016 condensed interim consolidated financial statements.

SUMMARY OF QUARTERLY RESULTS
The following table and discussion highlights the second quarter of 2016 results relative to the preceding 7 quarters:

	2016		2015				2014
	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
FINANCIAL
Revenue, Upstream	62.2	45.9	25.6	110.6	120.7	107.4	172.7	223.1
Revenue, Downstream(1)		—	—	—	—	—	321.2	877.0
Total Revenues and other income(2)	62.2	45.9	25.6	110.6	120.7	107.4	493.9	1,100.1
Net income (loss) from continuing operations	(65.7)	(13.1)	(894.2)	(588.7)	(87.0)	(223.5)	(275.8)	197.0
Net loss from discontinued operations		—	(15.5)	—	—	—	(61.7)	(277.9)
Net loss	(65.7)	(13.1)	(909.7)	(588.7)	(87.0)	(223.5)	(337.5)	(80.9)
OPERATIONS
Continuing Operations
Daily sales volumes (boe/d)	34,440	36,986	38,141	43,356	41,716	43,770	42,539	44,794
Realized price prior to hedging ($/boe)	26.50	20.86	27.89	31.47	37.85	31.85	47.99	62.99
Discontinued Operations(1)
Average daily throughput (bbl/d)	—	—	—	—	—	—	76,455	73,495
Average refining gross margin (US$/bbl)(3)	—	—	—	—	—	—	2.76	4.09

(1)	Downstream operations have been classified as “Discontinued Operations” as a result of disposition on November 13, 2014.
(2)	This is an additional GAAP measure; please refer to “Additional GAAP Measures” in this MD&A.
(3)	This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.

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

• Total revenues were highest in the third quarter of 2014, as a result of high daily sales volumes and throughput volumes from discontinued operations and lowest in the fourth quarter of 2015 due to low realized prices combined with low sales volumes from continuing operations and the absence of revenues from discontinued operations.

• The declines in Upstream’s sales volumes since 2014 were mainly due to asset dispositions and a capital program that was insufficient to offset declines in production.

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 derivative contracts impact net loss from period to period. For these reasons, the net loss may not necessarily reflect the same trends as revenues or cash from operating activities, nor is it expected to. The net loss from continuing operations in the second quarter of 2016 is mainly a result of lower realized prices and sales volumes, and a $10.6 million loss from joint ventures. The net loss from continuing operations in the first quarter of 2016 is mainly a result of lower realized prices and sales volumes, and a $18.5 million loss from joint ventures. The net loss from continuing operations in the fourth quarter of 2015 is mainly a result of lower realized prices and sales volumes, a $620.1 million impairment expense, and a $71.5 million loss from joint ventures. The net loss from continuing operations in the third quarter of 2015 is mainly a result of lower realized prices and sales volumes and a $542.0 million impairment expense. The net loss from continuing operations in the second quarter of 2015 is mainly a result of a result of lower realized prices and sales volumes and a $70.7 million impairment expense. The net loss from continuing operations in the first quarter of 2015 was mainly a result of lower realized prices and sales volumes, a $140.5 million foreign exchange loss and a $23.5 million impairment expense. The net loss from continuing operations in the fourth quarter of 2014 was mainly due to the $267.6 million impairment expense.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Further information on the basis of preparation and significant accounting policies and estimates can be found in the notes to the audited consolidated financial statements for the year ended December 31, 2015. There have been no changes to the accounting policies and critical accounting estimates in the second quarter of 2016.

RECENT ACCOUNTING PRONOUNCEMENTS

There were no new or amended standards issued during the six months ended June 30, 2016 that are applicable to Harvest in future periods. A description of additional accounting pronouncements that will be adopted by Harvest in future periods can be found in note 3 of the audited consolidated financial statements for the year ended December 31, 2015.

OPERATIONAL AND OTHER BUSINESS RISKS FOR CONTINUING OPERATIONS

Harvest’s operational and other business risks remain unchanged from those discussed in the annual MD&A and AIF for the year ended December 31, 2015 as filed on SEDAR at www.sedar.com.

CHANGES IN REGULATORY ENVIRONMENT

Harvest’s regulatory environment remains unchanged from that discussed in the annual MD&A and AIF for the year ended December 31, 2015 as filed on SEDAR atwww.sedar.com.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

INTERNAL CONTROL OVER FINANCIAL REPORTING

Harvest is required to comply with National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”. The certificate requires that Harvest disclosure in the interim MD&A any significant changes or material weaknesses in Harvest’s internal control over financial reporting that occurred during the period that have materially affected, or are reasonably likely to materially affect Harvest’s internal controls over financial reporting. Harvest confirms that no such significant changes or weaknesses were identified in Harvest’s internal controls over financial reporting during the second quarter and first six months of 2016 described in the annual MD&A for the year ended December 31, 2015 as filed on SEDAR atwww.sedar.com.

ADDITIONAL GAAP MEASURES

Throughout this MD&A, Harvest uses additional GAAP measures that are not defined under IFRS (hereinafter also referred to as “GAAP”). “Operating income (loss)” 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 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 netback”, “operating netback prior to/after hedging”, “average refining gross margin”, “cash contribution (deficiency) from operations” and “total debt to total capitalization”. “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 derivative contracts. “Average refining gross margin” is commonly used in the refining industry to reflect the net funds received from the sale of refined products after considering the cost to purchase the feedstock and is calculated by deducting purchased products for resale and processing from total revenue. “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 operations necessary to repay debt, make capital investments, and fund the settlement of decommissioning and environmental remediation liabilities. “Total debt to total capitalization” is a term defined in Harvest’s amended credit facility agreement for the purpose of calculation of the financial covenant. 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 cash contribution (deficiency) which is shown below.

Cash Contribution (Deficiency) from Operations

Cash contribution (deficiency) from operations represents operating income (loss) adjusted for non-cash expense items within: operating, general and administrative, exploration and evaluation, depletion, depreciation and amortization, gains on disposition of assets, derivative contracts gains or losses, impairment and other charges, and the inclusion of cash interest, realized foreign exchange gains or losses and other cash items not included in operating income (loss). The measure demonstrates the ability of Harvest’s upstream segment to generate cash from operations and is calculated before changes in non-cash working capital. 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.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

	Three Months Ended June 30
	Upstream				BlackGold				Total
	2016		2015		2016		2015		2016		2015
Operating loss	(51.3	)	(134.1	)	(2.7	)	(5.8	)	(54.1	)	(139.9	)
Adjustments:
Loss from joint ventures	10.6		10.1		—		—		10.6		10.1
Operating, non-cash	0.2		(0.4	)	—		—		0.2		(0.4	)
General and administrative, non-cash	1.4		1.7		—		—		1.4		1.7
Exploration and evaluation, non-cash	—		3.6		—		—		—		3.6
Depletion, depreciation and amortization	66.6		98.8		0.2		0.1		66.8		98.9
(Gains) losses on disposition of assets	(17.7	)	5.8		—		—		(17.7	)	5.8
Unrealized (gains) losses on derivative contracts	5.6		(3.7	)	—		—		5.6		(3.7	)
Impairment and other charges, non-cash	—		70.7		—		—		—		70.7
Cash contribution (deficiency) from operations	15.4		52.5		(2.5	)	(5.7	)	12.9		46.8
Inclusion of items not attributable to segments:
Net cash interest									20.5		23.7
Realized foreign exchange losses (gains)									(18.4	)	0.3
Consolidated cash contribution from operations									10.8		22.8

	Six Months Ended June 30
	Upstream				BlackGold				Total
	2016		2015		2016		2015		2016		2015
Operating loss	(146.6	)	(244.0	)	(7.2	)	(7.0	)	(153.8	)	(251.0	)
Adjustments:
Loss from joint ventures	29.1		16.0		—		—		29.1		16.0
Operating, non-cash	0.3		(0.9	)	—		—		0.3		(0.9	)
General and administrative, non-cash	0.9		2.0		—		—		0.9		2.0
Exploration and evaluation, non-cash	2.1		4.6		—		—		2.1		4.6
Depletion, depreciation and amortization	141.3		197.1		0.3		0.2		141.6		197.3
(Gains) losses on disposition of assets	(17.3	)	5.3		—		—		(17.3	)	5.3
Unrealized (gains) losses on derivative contracts	6.4		(2.6	)	—		—		6.4		(2.6	)
Impairment and other charges, non-cash	—		94.2		—		—		—		94.2
Cash contribution (deficiency) from operations	16.2		71.7		(6.9	)	(6.8	)	9.3		64.9
Inclusion of items not attributable to segments:
Net cash interest									44.5		35.1
Realized foreign exchange losses (gains)									(25.2	)	0.9
Consolidated cash contribution (deficiency) from operations									(10.0	)	28.9

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

FORWARD-LOOKING INFORMATION

This MD&A highlights significant business results and statistics from the consolidated financial statements for the three months and six months ended June 30, 2016 and the accompanying notes thereto. In the interest of providing Harvest’s lenders and potential lenders with information regarding Harvest, including the Company’s assessment of 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 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 regulatory reports and filings made with securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management’s future course of action would depend on the assessment of all information at that time. Please also refer to “Operational and Other Business Risks” in this MD&A and “Risk Factors” in the Annual Information Form for detailed discussion on these risks.

Forward-looking statements in this MD&A include, but are not limited to: commodity prices, price risk management activities, acquisitions and dispositions, capital spending and allocation of such to various projects, reserve estimates and ultimate recovery of reserves, potential timing and commerciality of Harvest’s capital projects, the extent and success rate of Upstream and BlackGold drilling programs, the ability to achieve the maximum capacity from the BlackGold central processing facilities, availability of the credit facility, access and ability to raise capital, ability to maintain debt covenants, debt levels, recovery of long-lived assets, the timing and amount of decommission and environmental related costs, income taxes, cash from operating activities, regulatory approval of development projects 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.

All of the forward-looking statements in this MD&A are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although Harvest believes that these assumptions are reasonable based on the information available to us on the date such assumptions were made, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that the Company will conduct its operations and achieve results of operations as anticipated; that its development plans and sustaining maintenance programs will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of the Company’s reserve volumes; commodity price, operation level, and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund the Company’s capital and operating requirements as needed; and the extent of Harvest’s liabilities. Harvest believes the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

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  MANAGEMENT’S DISCUSSION AND ANALYSIS

Although management believes that the forward-looking information is reasonable based on information available on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Therefore, readers are cautioned not to place undue reliance on forward-looking statements as the plans, intentions or expectations upon which the forward-looking information is based might not occur. 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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