Q2 2015 MD&A

MANAGEMENT’S DISCUSSION AND ANALYSIS

Dated as at August 19, 2015

The following Management’s Discussion and Analysis ("MD&A") is a review of the operations and current financial position for the three and six months ended June 30, 2015 for Hemisphere Energy Corporation ("Hemisphere" or the "Company") and should be read in conjunction with the unaudited interim condensed financial statements and related notes for the three and six months ended June 30, 2015, and the audited annual financial statements and related notes for the year ended December 31, 2014. These documents and additional information relating to the Company, including the Company’s Annual Information Form, are available on SEDAR at www.sedar.com or the Company’s website at www.hemisphereenergy.ca.

The information in this MD&A is based on the unaudited interim condensed financial statements which were prepared in accordance with International Financial Reporting Standards ("IFRS") applicable to the preparation of unaudited interim condensed financial statements including International Accounting Standard 34 Interim Financial Reporting, as issued by the International Accounting Standards Board.

This MD&A contains non-IFRS measures and forward-looking statements. Readers are cautioned that this document should be read in conjunction with Hemisphere’s disclosure under “Non-IFRS Measures” and “Forward-Looking Statements” included at the end of this MD&A. All figures are in Canadian dollars unless otherwise noted. Tables may not add due to rounding. Certain prior period amounts may have been reclassified to conform to the current period’s presentation.

Business Overview

Hemisphere produces oil and natural gas from its Jenner and Atlee Buffalo properties in southeast Alberta. The Company is headquartered in Vancouver, British Columbia and is traded on the TSX Venture Exchange under the symbol "HME".

Jenner, Alberta

Hemisphere has an average working interest of 92% in 26,290 net acres and has continued to build a land position in the Jenner area through Crown land sales and strategic acquisitions. The property is accessible year-round and is located east of Brooks in southeastern Alberta.

Atlee Buffalo, Alberta

The Company operates 100% of its wells in the Atlee Buffalo area. The property is accessible year-round and is located 30 kilometres east of the Company’s Jenner property in southeastern Alberta. Hemisphere has a 100% working interest in 5,432 net acres and has been building a land position in Atlee Buffalo through Crown land sales and strategic acquisitions.

Operating Results

The Company generated funds flow from operations of $1,314,073 ($0.02/share) during the second quarter of 2015 as compared to $1,550,661 ($0.02/share) during the second quarter of 2014. For the six months ended June 2015 and 2014, the Company generated funds flow from operations of $2,563,214 ($0.03/share) and $3,058,768 ($0.05/share), respectively. These changes in funds flow from operations are the result of the decline in commodity prices which began in the fourth quarter of 2014 and persisted through the first half of 2015.

Hemisphere Energy Corporation

2	Q2 2015 MD&A

For the second quarter of 2015, the Company reported a net loss of $575,484 ($0.01/share) compared to a net income of $554,465 ($0.01/share) for the second quarter of 2014. The Company reported a net loss of $1,221,830 ($0.02/share) for the six months ended June 30, 2015 as compared to a net income of $1,180,484 ($0.02/share) for the same period in 2014. The net losses for the three and six months ended June 30, 2015 include a deferred tax expense of $405,100.

Production

	Three Months Ended June 30		Six Months Ended June 30
By product:	2015	2014	2015	2014
Oil (bbl/d)	655	454	743	471
Natural gas (Mcf/d)	1,149	584	1,055	529
NGL (bbl/d)	3	2	3	1
Total (boe/d)	849	553	922	560
Oil and NGL weighting	77%	82%	81%	84%

In the second quarter of 2015, the Company’s average daily production increased to 849 boe/d (77% oil and NGL) which represents an increase of 54% over the second quarter of 2014. The Company experienced some downtime due to workovers performed on three wells in the second quarter of 2015 which resulted in a production shortfall of 30 bbl/d of oil. For the six months ended June 30, 2015, the Company’s average daily production increased by 65% over the comparable period in 2014. This increase in production can be attributed to the successful development of the Company’s Atlee Buffalo and Jenner properties in 2014 and the optimization of production from existing wells.

Average Benchmark and Realized Prices

		Three Months Ended June 30				Six Months Ended June 30
		2015		2014		2015		2014
Benchmark prices
WTI ($US/bbl)⁽¹⁾	$	57.94	$	102.96	$	53.29	$	100.82
Exchange rate (1 $US/$C)		1.2289		1.0912		1.2344		1.9071
WTI ($C/bbl)		71.21		112.36		65.78		110.61
WCS ($C/bbl)⁽²⁾		57.05		90.39		49.59		86.88
AECO natural gas ($/Mcf)⁽³⁾		2.62		4.63		2.66		5.07
Average realized prices
Crude oil ($/bbl)		50.49		85.72		42.43		81.17
Natural gas ($/Mcf)		2.57		4.64		2.60		4.54
NGL ($/bbl)		22.56		68.24		22.02		68.24
Combined ($/boe)	$	42.49	$	75.47	$	37.24	$	72.66

Notes:

(1)	Represents price of West Texas Intermediate Oil.
(2)	Represents price of Western Canadian Select.
(3)	Represents the Alberta 30 day spot AECO price.

Hemisphere Energy Corporation

Q2 2015 MD&A

The Company’s oil and natural gas sales may vary over periods as a result of changes in commodity prices and/or production volumes. The West Texas Intermediate pricing ("WTI") at Cushing, Oklahoma is the benchmark reference price for North American crude oil prices. Canadian oil prices, including Hemisphere’s crude oil, are based on the WTI price and adjusted for transportation, quality and the currency conversion rates from United States dollar ("USD") to Canadian dollar.

The Company’s combined average realized price decreased by 44% from $75.47/boe during the second quarter of 2014 to $42.49/boe during the second quarter of 2015. For the six months ended June 30, 2015, the Company’s combined average realized price decreased by 49% to $37.24/boe. These decreases are primarily the result of the decline in WTI despite tighter differentials and a favourable exchange rate in the first and second quarters of 2015. The result of the decline in WTI is also reflected in the decreases of the Company’s average realized oil prices for the three and six months ended June 30, 2015 to $50.49/bbl and $42.43/bbl, respectively, from the comparable periods in 2014. The decline and persistence of low oil prices is due to an oversupply of oil in the global market.

WTI price increased slightly in the second quarter of 2015, which resulted in increases of the Company’s average realized oil price by $14.48/bbl and its combined average realized price by $9.78/boe over the first quarter of 2015. Although WTI prices showed signs of recovery in the second quarter of 2015, they have since dropped in the third quarter and have also been subject to an increased differential between WTI and Western Canadian Select pricing. The exchange rate has continued to be favourable in the third quarter of 2015 due to the low Canadian dollar.

The Company’s average realized natural gas price decreased for the three and six months ended June 30, 2015 by $2.07/Mcf and $1.94/Mcf, respectively, from the comparable periods in 2014. These decreases are in line with the decline in AECO benchmark pricing for the three and six months ended June 30, 2015.

Revenue

		Three Months Ended June 30				Six Months Ended June 30
		2015		2014		2015		2014
Oil	$	3,009,671	$	3,540,924	$	5,703,496	$	6,917,044
Natural gas		268,741		246,384		496,762		434,300
NGL		5,608		12,153		12,025		12,153
Total	$	3,284,020	$	3,799,461	$	6,212,284	$	7,363,497

Revenue for the three and six months ended June 30, 2015 decreased by 14% and 16%, respectively, from the comparable periods in 2014. These decreases can be attributed to the reduction in the Company’s combined average realized price for the three and six months ended June 30, 2015, despite the Company generating significant production increases during those periods.

The Company’s revenue for the three months ended June 30, 2015 increased by 12% over the first quarter of 2015 as a result of the 30% increase in the Company’s combined average realized price.

Hemisphere Energy Corporation

4	Q2 2015 MD&A

Operating Netback

		Three Months Ended June 30				Six Months Ended June 30
		2015		2014		2015		2014
Operating netback
Revenue	$	3,284,020	$	3,799,461	$	6,212,284	$	7,363,497
Royalties		214,321		777,349		456,032		1,329,017
Operating costs		889,930		840,602		1,498,427		1,813,929
Transportation costs		225,523		170,398		475,593		331,436
Operating netback	$	1,954,246	$	2,011,113	$	3,782,232	$	3,889,115
Operating netback ($/boe)
Revenue	$	42.49	$	75.47	$	37.24	$	72.66
Royalties		2.77		15.41		2.73		13.10
Operating costs		11.51		16.70		8.98		17.90
Transportation costs		2.92		3.38		2.85		3.27
Operating netback ($/boe)	$	25.28	$	39.98	$	22.67	$	38.39

Royalties for the second quarter of 2015 were $2.77/boe, representing an 82% decrease from the second quarter of 2014. For the six months ended June 30, 2015, royalties decreased by 79% from the comparable period in 2014. These significant reductions are the result of 12 new horizontal wells drilled in 2014 which have lower associated royalty rates on initial production due to an 18 month Crown royalty holiday. Crown royalties also declined as a result of a lower Crown royalty par price in the first half of 2015 due to commodity price declines. Finally, the Company received a one-time retroactive rebate in Crown royalties as a result of a change in the royalty rate being applied to four of the Company’s producing wells. The royalty rebate accounts for a reduction in royalties of $0.87/boe for the six months ended June 30, 2015. As Crown royalty par price is set based on commodity prices, the Company expects to see low Crown royalties in the third quarter of 2015 given the current pricing environment.

Operating costs include all costs for gathering, processing, dehydration, compression, water processing and marketing of the oil, natural gas and NGLs, as well as additional costs incurred periodically for maintenance and repairs. Operating costs decreased for the three and six months ended June 30, 2015 by $5.19/boe and $8.92/boe, respectively, from the comparable periods in 2014. These decreases are the result of increased production levels in Atlee Buffalo which have low operating costs per boe, as well as realized economies of scale as a result of production from new wells drilled in 2014. The Company has also shut-in four wells with high operating costs in order to maximize operating netbacks and cash flow for the period. In the second quarter of 2015, the Company performed workovers on three horizontal oil wells required to bring them back on production. The costs associated with these workovers for the three and six months ended June 30, 2015 account for $2.26/boe and $1.07/boe, respectively, of the Company’s operating costs.

Transportation costs include all costs incurred to transport emulsion and oil and gas sales to processing and distribution facilities. Transportation costs decreased for the three and six months ended June 30, 2015 by $0.46/boe and $0.42/boe, respectively, from the comparable periods in 2014. These decreases are the result of the Company’s voluntary shut-in of higher water-cut wells that require trucking to facilities for processing.

Operating netback for the three and six months ended June 30, 2015 were $25.28/boe and $22.67/boe, respectively. The Company experienced decreases in operating netback in 2015 as a result of the significant decline in commodity prices, despite reductions in royalties and the Company’s successful efforts in cutting operating costs. Operating netback increased by $4.86/boe over the first quarter of 2015 as a result of the 30% increase in the Company’s combined average realized price.

Hemisphere Energy Corporation

Q2 2015 MD&A

Exploration and Evaluation

Exploration and evaluation expenses generally consist of certain geological and geophysical costs, expiry of undeveloped lands, and costs of uneconomic exploratory wells. Exploration and evaluation expenses for the three months ended June 30, 2015 and 2014 were $6,908 and $12,513, respectively. For the six months ended June 30, 2015 and 2014, exploration and evaluation expenses were $14,300 and $41,666, respectively.

Depletion and Depreciation

		Three Months Ended June 30				Six Months Ended June 30
		2015		2014		2015		2014
Depletion expense	$	1,447,286	$	985,773	$	3,089,333	$	1,861,117
Depreciation expense		3,364		1,670		6,727		2,603
Total	$	1,450,649	$	987,443	$	3,096,060	$	1,863,720
$ per boe	$	18.77	$	19.61	$	18.56	$	18.39

The depletion rate is calculated using the unit-of-production method on Proved and Probable oil and natural gas reserves, taking into account the future development costs to develop and produce undeveloped and non-producing reserves. Depletion and depreciation expense for the second quarter of 2015 increased by $463,206 over the second quarter of 2014. For the six months ended June 30, 2015, depletion and depreciation expense increased by $1,232,340 over the comparable period in 2014.

Theses increases are the result of a higher depletion rate caused by the Company’s production growth during the three and six months ended June 30, 2015. The depletion rate was applied to the Company’s depletable asset base which, for the six months ended June 30, 2015, also increased by 37% over the comparable period in 2014. Depletion expense for the comparative quarter has been revised in accordance with the Company’s change in accounting for depleting its petroleum and natural gas properties from using the unit-of-production method based on production volumes in relation to estimated Proved reserves to total estimated Proved and Probable reserves. For further information, see Note 2(e) of the Company’s unaudited interim condensed financial statements for the three and six months June 30, 2015.

Capital Expenditures

		Three Months Ended June 30				Six Months Ended June 30
		2015		2014		2015		2014
Land and lease	$	5,600	$	90,660	$	13,034	$	105,252
Geological and geophysical		28,408		71,224		44,440		187,315
Drilling and completions		283,407		2,614,682		333,106		5,554,894
Facilities and infrastructure		241,080		715,041		301,204		1,936,724
Development capital		558,495		3,491,607		691,783		7,784,185
Property acquisitions		271,000		-		271,000		124,739
Fixed assets		-		23,584		-		23,584
Disposition proceeds		-		-		-		(50,000	)
Total capital expenditures⁽¹⁾	$	829,495	$	3,515,191	$	962,783	$	7,882,507

Note:

(1)

Total capital expenditures exclude decommissioning obligations.

Hemisphere Energy Corporation

6	Q2 2015 MD&A

The development capital spent during the second quarter of 2015 included preliminary costs relating to the Company’s planned waterflood pilot schemes in Atlee Buffalo which included the installation of required equipment to the Company’s facilities and the conversion of two wells into a water injector and a source well. The Company is anticipating first water injection at its first waterflood pilot scheme by the end of the third quarter of 2015. The Company also spent development capital in Jenner to improve a water disposal well by adding new perforations and completing an acid job. As part of the Company’s future capital program, some preliminary costs were also spent in the second quarter of 2015 on converting an abandoned well into a disposal well. Finally, the Company completed a strategic tuck-in acquisition of the remaining 15% working interest in 1.75 sections (1,120 acres) of land in Atlee Buffalo. The Company now has 100% working interest in this land.

The Company has taken a conservative approach on capital spending and investment in 2015 as a result of the current commodity pricing environment. The Company’s focus for the remainder of 2015 will be on strategic capital projects that add production and reserves while providing long-term stability and increased oil recovery to the Company’s assets.

The following table is a reconciliation of the Company’s capital expenditures to the additions of property and equipment as shown in Note 8 of the Company’s unaudited interim condensed financial statements for the three and six months ended June 30, 2015 and 2014:

		Three Months Ended June 30						Six Months Ended June 30
		2015			2014			2015			2014
Total capital expenditures	$	829,495		$	3,515,191		$	962,783		$	7,882,507
Increase in decommissioning obligations		31,287			-			31,287			30,658
Evaluation and exploration expenditures		(220,231	)		(2,152,881	)		(242,504	)		(2,801,980	)
Gain on disposition		-			-			-			2,942
Additions to property and equipment	$	640,551		$	1,362,310		$	751,567		$	5,114,128

General and Administrative Expenses ("G&A")

		Three Months Ended June 30						Six Months Ended June 30
		2015			2014			2015			2014
Gross G&A	$	565,333		$	480,612		$	1,036,235		$	908,289
Capitalized G&A and overhead recoveries		(47,842	)		(102,032	)		(55,301	)		(255,969	)
Net G&A		517,491			378,580			980,934			652,320
$ per boe	$	6.70		$	7.52		$	5.88		$	6.44
Share-based payments		2,742			-			221,752			-
Total G&A		520,233			378,580			1,202,686			652,320
$ per boe	$	6.73		$	7.52		$	7.21		$	6.44

Gross G&A for the second quarter of 2015 increased by $84,721 over the comparable quarter in 2014 due to higher staffing costs, increased insurance coverage, and increased investor relations activities. For the six months ended June 30, 2015, gross G&A increased by $127,946 over the comparable period in 2014.

The Company capitalizes certain G&A which can be attributed to any costs incurred during the period relating to its development and exploration activities. For the three and six months ended June 30, 2015, capitalized G&A decreased by $54,190 and $200,668, respectively, from the comparable periods in 2014. These decreases in capitalized G&A are consistent with the Company’s decision to defer major capital expenditures and drilling activity until commodity prices have recovered.

Hemisphere Energy Corporation

Q2 2015 MD&A

For the three and six months ended June 30, 2015, the Company realized decreases in net G&A of $0.82/boe and $0.56/boe, respectively, from the comparable periods in 2014 as a result of increased production rates.

Share-based payments are non-cash charges which reflect the estimated value of stock options issued to directors, employees and consultants of the Company. Share-based payments for the three months ended June 30, 2015 and 2014 were $2,742 and $nil, respectively. The Company granted 25,000 incentive stock options in the first quarter of 2015 to an individual performing investor-related services which will vest quarterly over a twelve-month period. In the second quarter of 2015, 6,250 stock options vested resulting in the recognition of $2,742 in share-based payments. For the six months ended June 30, 2015 and 2014, the Company recorded share-based payments of $221,752 and $nil, respectively. This increase is the result of granting 1,325,000 incentive stock options in the first quarter of 2015. All share-based payments are considered to be part of the Company’s G&A.

Finance Expense

		Three Months Ended June 30				Six Months Ended June 30
		2015		2014		2015		2014
Finance expense
Interest expense	$	115,775	$	64,918	$	223,783	$	128,861
Part XII.6 tax		-		4,440		-		7,500
Accretion of provision		31,066		8,753		62,131		17,506
Total	$	146,841	$	78,111	$	285,914	$	153,866
$ per boe	$	1.90	$	1.55	$	1.71	$	1.52

Finance expense for the three and six months ended June 30, 2015 increased by $68,730 and $132,048, respectively, over the comparable periods in 2014. These increases are a result of the increased accretion expense for the quarter, and the interest expense incurred on the utilization of the Company’s credit facility which carried a higher balance in 2015.

Accretion expense represents the adjusted present value of the Company’s decommissioning obligations which includes the abandonment and reclamation costs associated with wells and facilities. For the three and six months ended June 30, 2015, accretion expense increased by $22,313 and $44,625, respectively, over the comparable periods in 2014 due to the additional decommissioning obligations associated with the new wells drilled in the second half of 2014. The Company also changed its estimate of decommissioning obligations based on Directive 011 as set by the Alberta Energy Regulator, which increased the total decommissioning obligation estimate at December 31, 2014.

Tax Pools and Deferred Taxes

Hemisphere has approximately $45.3 million of tax pools available to be applied against future income for tax purposes. Based on available pools and current commodity prices, the Company does not expect to pay income tax in 2015 or in 2016. Taxes payable beyond 2016 will primarily be a function of commodity prices, capital expenditures and production volumes.

For the three and six months ended June 30, 2015, deferred tax expense of $405,100 was recorded based on the taxable income generated in excess of tax pools resulting from lower capital expenditures which reduced the Company’s deferred tax asset to $1,236,816. This deferred tax expense includes a one-time adjustment of $28,027, which resulted from the increase in the Alberta corporate tax rate from 10% to 12%.

Hemisphere Energy Corporation

8	Q2 2015 MD&A

Selected Annual Information

The following are highlights of the Company’s financial data for the three most recently completed fiscal years:

		Year Ended			Year Ended			10 Months Ended
		December 31, 2014			December 31, 2013			December 31, 2012
Average daily production (boe/d)		683			463			408
Petroleum and natural gas revenue	$	16,635,279		$	10,573,199		$	7,875,723
Petroleum and natural gas netback		9,275,653			5,607,492			4,657,308
Funds flow from operations⁽¹⁾		6,673,033			3,789,202			3,265,657
Per share, basic and diluted		0.10			0.07			0.06
Net loss⁽²⁾		(1,667,807	)		(510,266	)		(472,045	)
Per share, basic and diluted		(0.02	)		(0.01	)		(0.01	)
Average realized price ($/boe)		66.68			62.55			63.15
Operating netback ($/boe)⁽³⁾		37.19			33.17			37.33
Capital expenditures, including property acquisitions		21,316,366			9,969,174			11,888,398
Net debt⁽⁴⁾		11,644,609			6,330,906			3,927,595
Bank indebtedness		7,184,147			4,500,000			1,035,000
Total assets⁽²⁾		48,951,632			32,195,577			24,486,865

Notes:

(1)	Funds flow from operations is a non-IFRS measure that represents cash generated by operating activities, before changes in non-cash working capital and may not be comparable to measures used by other companies.
(2)	Certain annual amounts were restated retrospectively due to a change in accounting policy as disclosed in Note 4 of the Company’s audited annual financial statements for the year ended December 31, 2014.
(3)	Operating netback is a non-IFRS measure calculated as the Company’s oil and gas sales, less royalties, operating expenses and transportation costs per barrel of oil equivalent.
(4)	Net debt is a non-IFRS measure calculated as current assets minus current liabilities including bank indebtedness and excluding flow- through share premium.

Summary of Quarterly Results

	2015						2014			2013
	June. 30		Mar. 31		Dec. 31		Sep. 30	Jun. 30	Mar. 31	Dec. 31		Sep. 30
	Q2⁽²⁾		Q1⁽³⁾		Q4⁽⁴⁾		Q3⁽⁵⁾	Q2⁽⁶⁾	Q1⁽⁷⁾	Q4⁽⁸⁾		Q3⁽⁹⁾
Average daily production (boe/d)	849		995		885		725	553	567	569		461
Petroleum and natural gas revenue	3,284,020		2,928,264		4,568,286		4,703,496	3,799,461	3,564,036	2,958,107		3,165,562
Petroleum and natural gas netback	1,954,246		1,827,986		2,534,334		2,852,204	2,011,113	1,878,003	1,246,355		1,970,836
Funds flow from operations	1,314,073		1,249,142		1,334,422		2,279,842	1,550,661	1,508,107	579,824		1,570,350
Per share, basic and diluted	0.02		0.02		0.02		0.03	0.02	0.02	0.01		0.03
Net income (loss)⁽¹⁾	(575,484	)	(646,345	)	(3,568,603	)	720,312	554,465	626,019	(1,202,692	)	673,023
Basic and diluted income (loss) per share	(0.01	)	(0.01	)	(0.05	)	0.01	0.01	0.01	(0.02	)	0.01
Combined average realized price ($/boe)	42.49		32.71		56.10		70.52	75.47	69.89	56.55		74.56
Operating netback ($/boe)	25.28		20.42		31.14		42.79	39.98	36.83	23.83		46.42

Notes:

(1)

Certain quarterly amounts were restated retrospectively due to a change in accounting policy as disclosed in Note 4 of the Company’s audited annual financial statements for the year ended December 31, 2014.

(2)

Funds flow from operations and petroleum and natural gas netbacks have shown a slight improvement over the first quarter of 2015 due to a 30% increase in the Company’s combined average realized price, but have remained low compared to 2014 as a result of the decline in commodity prices. Due to taxable income generated in excess of tax pools from lower capital expenditures, the Company utilized deferred tax assets resulting in a deferred tax expense of $405,100 for the second quarter of 2015.

Hemisphere Energy Corporation

Q2 2015 MD&A

(3)	The decreases in net income, funds flow from operations and petroleum and natural gas netbacks can be attributed to the decrease in the Company’s combined average realized price resulting from the decline in oil prices.
(4)	A significant portion of the loss is due to the $2,702,925 recorded in property impairment and an increase in depletion expense as a result of a change in the Company’s depletion accounting policy.
(5)	Net income can be attributed to a combination of the increase in the Company’s production from its summer drilling program and the improvement of netback resulting from decreased operating and transportation costs.
(6)	The improvement in net income over certain prior quarters is primarily due to the Company’s increase in the combined average realized price resulting in higher operating netback.
(7)	The improvement in net income is primarily due to the Company’s increased production levels from the drilling of three new wells and an increase in combined average realized price.
(8)	A significant portion of the net loss is due to the increase in depletion expense as a result of the Company’s increase in production.
(9)	The high net income is primarily due to the Company’s increased production levels and average realized price for the quarter.

Outstanding Share Capital

	August 19, 2015	June 30, 2015	December 31, 2014
Fully diluted share capital
Common shares issued and outstanding	75,803,498	75,803,498	75,368,498
Stock options	6,860,000	6,860,000	5,970,000
Total fully diluted	82,663,498	82,663,498	81,338,498

Subsequent to June 30, 2015, there were no events that would have impacted the Company’s share capital.

The Company has the following stock options outstanding and exercisable as at August 19, 2015:

		Balance Outstanding	Balance Exercisable
Exercise Price	Expiry Date	August 19, 2015	August 19, 2015
$0.26	30-Sep-15	490,000	490,000
$0.30	23-Dec-15	375,000	375,000
$0.30	27-Jan-16	200,000	200,000
$0.38	9-Feb-16	50,000	50,000
$0.40	26-May-16	475,000	475,000
$0.48	5-Jul-16	50,000	50,000
$0.70	8-Feb-17	1,500,000	1,500,000
$0.65	24-Apr-17	75,000	75,000
$0.61	5-Jul-17	425,000	425,000
$0.50	8-Mar-18	250,000	250,000
$0.55	6-Jan-19	660,000	660,000
$0.65	29-Sep-19	785,000	785,000
$0.61	7-Oct-19	200,000	200,000
$0.24	29-Jan-20	1,225,000	1,206,250
$0.39	1-Mar-20	100,000	100,000
		6,860,000	6,835,000
Weighted-average exercise price		$0.49	$0.49

Liquidity and Capital Management

The Company’s net debt as at June 30, 2015 and December 31, 2014 were $9,938,019 and $11,644,609, respectively, representing a decrease in net debt of $1,706,590.

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10	Q2 2015 MD&A

Financing

The Company’s cash provided by financing activities for the three months ended June 30, 2015 and 2014 were $nil and $9,214,919, respectively. For the six months ended June 30, 2015 and 2014, cash provided by financing activities were $108,750 and $9,243,044, respectively. For the six months ended June 30, 2015, the Company issued 435,000 common shares through the exercise of stock options at $0.25 each for gross proceeds of $108,750.

b)	Capital Resources

		As at
		June 30, 2015		December 31, 2014
Shareholders’ equity	$	29,800,909	$	30,692,235
Undrawn component of bank credit facilities		5,561,166		7,815,853
Total capital	$	35,362,075	$	38,508,088

The Company has a demand operating credit facility in the amount of $15,000,000 with Alberta Treasury Branches ("ATB"), which was renewed in July 2015. Funds available under the credit facility are $14,000,000 and access to the remaining $1,000,000 is based on additional approval from ATB. The facility is secured by a general security agreement and a floating charge on all lands of the Company. The facility bears interest at the bank’s prime rate plus 1.75%, as well as a standby charge for any un-drawn funds.

Pursuant to the terms of the credit facility, the Company has provided a financial covenant that at all times its working capital ratio shall not be less than 1.0. The working capital ratio is defined under the terms of the credit facilities as current assets including the undrawn portion of the revolving operating demand line credit facility, to current liabilities, excluding any current bank indebtedness.

At June 30, 2015, the Company has drawn a total of $9,438,835 from its credit facility (December 31, 2014 - $7,184,147) and was in compliance with the above financial covenant. The Company’s next review is scheduled for October 31, 2015.

The Company manages its capital with the following objectives:

	•	Ensure sufficient flexibility to achieve the Company’s ongoing business objectives including the replacement of production, funding of future growth opportunities, and pursuit of accretive acquisitions; and

	•	Maximize shareholder return through enhancing the Company’s share value.

The Company monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the business and industry in general. The capital structure of the Company is composed of shareholders’ equity and the undrawn component of the Company’s credit facilities. The Company may manage its capital structure by issuing new shares, repurchasing outstanding shares, obtaining additional financing from the Company’s credit facilities, issuing new debt instruments, other financial or equity-based instruments, adjusting capital spending, or disposing of assets. The capital structure is reviewed on an ongoing basis.

Hemisphere Energy Corporation

Q2 2015 MD&A

Related Party Transactions

For the three and six months ended June 30, 2015 the Company paid fees of $10,000 and $20,000, respectively, to a director of the Company. These fees were charged for services provided by the Chairman of the Company’s Board of Directors.

Compensation to key executive personnel, consisting of the Company’s officers, directors and Chairman, was paid as follows:

	Three Months Ended June 30			Six Months Ended June 30
	2015	2014		2015		2014
Short-term benefits	205,000	157,500	$	410,000	$	315,000
Share-based payments	-	-		135,660		-

Short-term benefits, which are primarily salaries and wages, have increased during the three six months ended June 30, 2015 mainly as the result of a technical consultant who transitioned to an officer in September 2014.

Commitment

The Company has a commitment to make monthly rental payments pursuant to the office rental agreement at its current location until May 30, 2018. The following table shows the Company’s rental commitment amounts for the next four fiscal years:

		2015			2016			2017			2018
Rental commitment	$	95,613		$	191,226		$	191,226		$	79,678

Off-Balance Sheet Arrangements

The Company has not entered into any off-balance sheet transactions.

Proposed Transactions

As of the effective date, there are no outstanding proposed transactions.

Critical Accounting Estimates and Judgements

The Company’s significant accounting estimates, judgements and policies are set out in Notes 2 and 3 of the audited annual financial statements for the year ended December 31, 2014 and have been consistently followed in the preparation of the unaudited interim condensed financial statements.

The preparation of the unaudited interim condensed financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that may affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. A discussion of specific estimates and judgements employed in the preparation of the Company’s unaudited interim condensed financial statements is included in the Company’s audited annual financial statements for the year ended December 31, 2014.

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12	Q2 2015 MD&A

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.

Newly Adopted Accounting Standards

Effective January 1, 2015, the Company has not adopted any new accounting standards. A full listing of future accounting pronouncements are disclosed in the Company’s annual audited financial statements for the year ended December 31, 2014.

Disclosure Controls and Procedures

Although TSX Venture ("TSX-V") listed companies are not required to provide representations in filings relating to the establishment and maintenance of disclosure controls and procedures ("DC&P"), the Company has taken initiative to assess the effectiveness of the Company’s DC&P, as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings ("NI 52-109"), under the supervision and with the participation of the Company’s Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"). Based on their evaluation, the Company’s CEO and CFO have concluded that, with the remediation of the material weaknesses in the internal controls over financial reporting as disclosed in the section below, the Company’s DC&P are effective to give reasonable assurance that the information required to be disclosed in the Company’s annual filings, interim filings or other reports filed, or submitted by the Company under securities legislation were recorded, processed, summarized and reported within the time periods specified under securities legislation, and the Company has included controls and procedures designed to ensure that information required to be so disclosed is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

Internal Controls over Financial Reporting

Management, including the Company’s CEO and CFO, is responsible for establishing and maintaining adequate internal controls over financial reporting ("ICFR") to provide reasonable assurance regarding the reliability of the Company’s financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. ICFR include those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company’s assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with IFRS, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Due to the inherent limitations of ICFR, they may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Hemisphere Energy Corporation

Q2 2015 MD&A

Although TSX-V listed companies are not required to provide representations in filings relating to the establishment and maintenance of ICFR, the Company, with the participation of the CEO and CFO, has assessed the effectiveness of the Company’s ICFR. The assessment was based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO 2013"). Management remediated the Company’s ICFR by instituting controls specific to (i) the process for evaluating and reviewing impairment indicators over petroleum and natural gas properties; and (ii) the process for determining the Company’s decommissioning obligations. Based on its assessment, the CEO and CFO have concluded that the Company’s ICFR are effective with the remediation of the above mentioned items and conformity with COSO 2013.

Financial Instruments

Fair value estimates of financial instruments are made at a specific point in time, based on relevant information about financial markets and specific financial instruments. As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, changes in assumptions can significantly affect estimated fair values. At June 30, 2015, the Company's financial instruments include accounts receivable, reclamation deposits, bank indebtedness, accounts payable and accrued liabilities.

The fair values of accounts receivable, reclamation deposits, bank indebtedness, accounts payable and accrued liabilities approximate their carrying values due to the short-term maturity of these financial instruments.

Risks

The Company’s activities expose it to a variety of risks that arise as a result of its exploration, development, production and financing activities. These risks and uncertainties include, among other things, volatility in market prices for oil and natural gas, general economic conditions in Canada, the US and globally and other factors described under "Risk Factors" in Hemisphere’s most recently filed Annual Information Form which is available on the Company’s website at www.hemisphereenergy.ca or on SEDAR at www.sedar.com. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

The following provides information about the Company’s exposure to some risks associated with the oil and gas industry, as well as the Company’s objectives, policies and processes for measuring and managing risk.

Business Risk

Oil and gas exploration and development involves a high degree of risk whereby many properties are ultimately not developed to a producing stage. There can be no assurance that the Company’s future exploration and development activities will result in discoveries of commercial bodies of oil and gas. Whether an oil and gas property will be commercially viable depends on a number of factors including the particular attributes of the reserve and its proximity to infrastructure, as well as commodity prices and government regulations, including regulations relating to prices, taxes, royalties, land tenure, land use, and environmental protection. The exact effect of these factors cannot be accurately predicted, and the combination of these factors may result in an oil and gas property not being profitable.

Hemisphere Energy Corporation

14	Q2 2015 MD&A

Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its payment obligations. This risk arises principally from the Company’s receivables from joint venture partners and oil and natural gas marketers and its reclamation deposits. Any risk associated with accounts receivable is minimized substantially by the financial strength of the Company’s joint venture partners, operators and marketers. The credit risk associated with reclamation deposits is mitigated by ensuring these financial assets are placed with major financial institutions with strong investment-grade ratings by a primary ratings agency. The Company does not anticipate any default. There are no balances past due or impaired.

The maximum exposure to credit risk is as follows:

		As at
		June 30, 2015		December 31, 2014
Accounts receivable
Trade receivables	$	1,123,699	$	1,041,843
Receivables from joint venture		49,976		95,355
Reclamation deposits		105,535		105,535
Total	$	1,279,210	$	1,242,733

The Company sells the majority of its oil production to a single oil marketer and, therefore, is subject to concentration risk which is mitigated by management’s policies and practices related to credit risk, as discussed above. The Company historically has never experienced any collection issues with its oil marketer.

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due. The Company manages liquidity risk by anticipating operating, investing and financing activities and ensuring that it will have sufficient liquidity to meet its liabilities when they become due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company. The Company prepares expenditure budgets on a quarterly and annual basis which are regularly monitored and updated when necessary in order to review debt forecasts and working capital requirements.

At June 30, 2015, the Company had net debt of $9,938,019 (December 31, 2014 - $11,644,609), which includes bank indebtedness of $9,438,835 (December 31, 2014 - $7,184,147). The Company funds its operations through production revenue and a demand operating credit facility. All of the Company’s financial liabilities have contractual maturities of less than 90 days.

Market risk

Market risk is the risk that changes in market prices, such as, foreign exchange rates, commodity prices, and interest rates will affect the value of the financial instruments. Market risk is comprised of interest rate risk, foreign currency risk, commodity price risk, and other price risk.

Hemisphere Energy Corporation

Q2 2015 MD&A

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. Borrowings under the Company’s credit facilities are subject to variable interest rates. A one percent change in interest rates would not have a material effect on net income (loss) and comprehensive income (loss).

Foreign currency risk

The Company’s functional and reporting currency is Canadian dollars. The Company does not sell or transact in any foreign currency; however, commodity prices are largely denominated in USD, and as a result the prices that the Company receives are affected by fluctuations in the exchange rates between the USD and the Canadian dollar. The exchange rate effect cannot be quantified, but generally an increase in the value of the Canadian dollar compared to the USD will reduce the prices received by the Company for its crude oil and natural gas sales. The Company did not have any foreign exchange rate swaps or related contracts in place as at the date of this document.

Commodity price risk

Commodity prices for petroleum and natural gas are impacted by global economic events that dictate the levels of supply and demand, as well as the relationship between the Canadian dollar and the USD. Significant changes in commodity prices may materially impact the Company’s funds flow from operations, and ability to raise capital. The Company has not entered into any commodity hedge contracts as at the date of this document.

Other price risk

Other price risk is the risk that the fair or future cash flows of a financial instrument will fluctuate due to changes in market prices, other than those arising from interest rate risk, foreign currency risk or commodity price risk. The Company is not exposed to significant other price risk.

Non-IFRS Measures

This document contains the terms "funds flow from operations", "operating netback", and "net debt" which are not recognized measures under IFRS and may not be comparable to similar measures presented by other companies.

The Company considers funds flow from operations to be a key measure that indicates the Company’s ability to generate the funds necessary to support future growth through capital investment and to repay any debt. Funds flow from operations is a measure that represents cash generated by operating activities, before changes in non-cash working capital and may not be comparable to measures used by other companies. Funds flow from operations per share is calculated using the same weighted-average number of shares outstanding as in the case of the earnings per share calculation for the period.

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16	Q2 2015 MD&A

A reconciliation of funds flow from operations to cash provided by operating activities is presented as follows:

		Three Months Ended June 30					Six Months Ended June 30
		2015		2014			2015		2014
Cash provided by operating activities	$	921,267	$	2,046,048		$	1,749,418	$	2,846,582
Change in non-cash working capital		392,806		(495,387	)		813,796		212,186
Funds flow from operations	$	1,314,073	$	1,550,661		$	2,563,214	$	3,058,768
Per share, basic and diluted	$	0.02	$	0.02		$	0.03	$	0.05

	b)	Operating netback is a benchmark used in the oil and natural gas industry and a key indicator of profitability relative to current commodity prices. Operating netback is calculated as oil and gas sales, less royalties, operating expenses and transportation costs on an absolute and per boe basis. These terms should not be considered an alternative to, or more meaningful than, cash flow from operating activities or net income or loss as determined in accordance with IFRS as an indicator of the Company’s performance.

	c)	Net debt (working capital) is closely monitored by the Company to ensure that its capital structure is maintained by a strong balance sheet to fund its future growth. Net debt is used in this document in the context of liquidity and is calculated as the total of the Company’s bank debt and current liabilities, less current assets. There is no IFRS measure that is reasonably comparable to net debt.

The following table outlines the Company calculation of net debt:

		As at
		June 30, 2015			December 31, 2014
Current assets	$	1,263,371		$	1,437,181
Current liabilities⁽¹⁾		(1,762,556	)		(5,897,643	)
Bank indebtedness		(9,438,835	)		(7,184,147	)
Net debt	$	9,938,019		$	(11,644,609	)

Note:

(1)

Excluding bank indebtedness.

Boe Conversion

Within this document, petroleum and natural gas volumes and reserves are converted to a common unit of measure, referred to as a barrel of oil equivalent ("boe"), using a ratio of 6,000 cubic feet of natural gas to one barrel of oil. Use of the term boe may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalent method and does not necessarily represent a value equivalency at the wellhead. This conversion conforms with the Canadian Securities Regulators National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.

Forward-Looking Statements

In the interest of providing Hemisphere’s shareholders and potential investors with information regarding the Company, including management’s assessment of the future plans and operations of Hemisphere, certain statements contained in this MD&A constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "potential", "target" and similar words suggesting future events or future performance. In particular, but without limiting the foregoing, this document may contain forward-looking statements pertaining to the following: volumes and estimated value of Hemisphere’s oil and natural gas reserves; the life of Hemisphere’s reserves; the volume and product mix of Hemisphere’s oil and natural gas production; future oil and natural gas prices; future operational activities; and future results from operations and operating metrics, including any future production growth and net debt. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

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Q2 2015 MD&A

With respect to forward-looking statements contained in this MD&A, the Company has made assumptions regarding, among other things: future capital expenditure levels; future oil and natural gas prices and differentials between light, medium and heavy oil prices; results from operations including future oil and natural gas production levels; future exchange rates and interest rates; Hemisphere’s ability to obtain equipment in a timely manner to carry out development activities; Hemisphere’s ability to market its oil and natural gas successfully to current and new customers; the impact of increasing competition; Hemisphere’s ability to obtain financing on acceptable terms; and Hemisphere’s ability to add production and reserves through our development and exploitation activities.

Although Hemisphere believes that the expectations reflected in the forward-looking statements contained in this MD&A, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this MD&A, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause Hemisphere’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things, the following: volatility in market prices for oil and natural gas; general economic conditions in Canada, the U.S. and globally; and the other factors described under "Risk Factors" in Hemisphere’s most recently filed Annual Information Form available on the Company’s website at www.hemisphereenergy.ca or on SEDAR at www.sedar.com. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

The forward-looking statements contained in this MD&A speak only as of the date of this document. Except as expressly required by applicable securities laws, Hemisphere does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement..

Hemisphere Energy Corporation

HEMISPHERE ENERGY CORP 6-K