| | Q1 2015 MANAGEMENT’S DISCUSSION & ANALYSIS | 3 |
MANAGEMENT’S DISCUSSION AND ANALYSIS
Dated as at May 27, 2015
The following Management’s Discussion and Analysis ("MD&A") is a review of the operations and current financial position for the three months ended March 31, 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 months ended March 31, 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 atwww.sedar.com or the Company’s website atwww.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 IAS 34 "Interim Financial Reporting", as issued by the International Accounting Standards Board ("IASB").
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.
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 approximately 25,650 net acres (10,380 hectares) and has continued to build a land position in the Jenner area through Crown land sales and strategic acquisitions and farm-ins. 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 7,192 net acres (2,911 hectares) and has been building a land position in Atlee Buffalo through Crown land sales and strategic acquisitions.
On May 19, 2015, 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 for a purchase price of $250,000. The Company now has 100% working interest in this land.
| Hemisphere Energy Corporation |
| 4 | Q1 2015 MANAGEMENT’S DISCUSSION & ANALYSIS |
Operating Results
The Company generated funds flow from operations of $1,249,142 ($0.02/share) during the first quarter of 2015, as compared to $1,508,107 ($0.02/share) during the first quarter of 2014. This change is due to the Company’s decreased revenue in the first quarter of 2015 resulting from the decline in commodity prices which began in the fourth quarter of 2014 and persisted through the first quarter of 2015.
For the three months ended March 31, 2015, the Company reported a net loss of $646,345 ($0.01/share) compared to a net income of $626,019 ($0.01/share) for the three months ended March 31, 2014.
Production
| | | Three Months Ended March 31 | |
| By product: | | 2015 | | | 2014 | |
| Oil (bbl/d) | | 832 | | | 488 | |
| Natural gas (Mcf/d) | | 960 | | | 473 | |
| NGL (bbl/d) | | 3 | | | - | |
| Total (boe/d) | | 995 | | | 567 | |
| Oil and NGL weighting | | 84% | | | 86% | |
In the first quarter of 2015, the Company’s average daily production increased to a record 995 boe/d (84% oil and NGL) which represents an increase of 12% over the fourth quarter of 2014 and 76% over the first quarter of 2014. This increase in production can be attributed to the successful development of the Company’s Atlee Buffalo and Jenner properties in 2014 and the optimization of production from existing wells.
Average Benchmark and Realized Prices
| | | Three Months Ended March 31 | |
| | | 2015 | | | 2014 | |
| Benchmark prices | | | | | | |
| WTI ($US/bbl)(1) | $ | 48.63 | | $ | 98.68 | |
| Exchange rate (1 $US/$C) | | 1.2397 | | | 1.1030 | |
| WTI ($C/bbl) | | 60.29 | | | 108.85 | |
| WCS ($C/bbl)(2) | | 43.56 | | | 83.38 | |
| AECO natural gas ($/Mcf)(3) | | 2.70 | | | 5.52 | |
| Average realized prices | | | | | | |
| Crude oil ($/bbl) | | 36.01 | | | 76.90 | |
| Natural gas ($/Mcf) | | 2.64 | | | 4.42 | |
| NGL ($/bbl) | | 21.56 | | | - | |
| Combined ($/boe) | $ | 32.71 | | $ | 69.89 | |
| Notes: |
| (1) | Represents posting prices of West Texas Intermediate Oil. |
| (2) | Represents posting prices of Western Canadian Select. |
| (3) | Represents the Alberta 30 day spot AECO posting prices. |
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 price postings, which is WTI-adjusted for transportation, quality and the currency conversion rates from United States dollar ("USD") to Canadian dollar.
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The Company’s combined average realized price decreased by 53% from $69.89 during the first quarter of 2014 to $32.71/boe during the first quarter of 2015. This decrease is the result of low oil prices which persisted through the first quarter of 2015 and is also reflected in the $40.89/bbl decrease from the Company’s average realized crude oil price during the first quarter of 2014. The decline in oil prices has been the result of an oversupply of oil in the global market which was partially offset by tighter oil differentials and a favourable exchange rate in the first quarter of 2015. WTI prices have showed signs of recovery in the second quarter of 2015, however, have not yet stabilized.
The Company’s average realized natural gas price also decreased in the first quarter of 2015 by $1.78/Mcf over the comparable quarter of 2014.
Revenue
| | | Three Months Ended March 31 | |
| | | 2015 | | | 2014 | |
| Oil | $ | 2,693,826 | | $ | 3,376,120 | |
| Natural gas | | 228,021 | | | 187,916 | |
| NGL | | 6,417 | | | - | |
| Total | $ | 2,928,264 | | $ | 3,564,036 | |
Revenue for the first quarter of 2015 decreased by 18% from the comparable quarter in 2014. This decrease can be attributed to the 53% reduction in the Company’s combined average realized price for the first quarter of 2015 as a result of the decline in commodity prices. Although the Company experienced production growth in the first quarter of 2015, this increase was more than offset by the decline in commodity prices resulting in lower revenue for the quarter.
Operating Netback
| | | Three Months Ended March 31 | |
| | | 2015 | | | 2014 | |
| Operating netback | | | | | | |
| Revenue | $ | 2,928,264 | | $ | 3,564,036 | |
| Royalties | | 241,711 | | | 551,669 | |
| Operating costs | | 608,497 | | | 973,327 | |
| Transportation costs | | 250,070 | | | 161,037 | |
| Operating netback | $ | 1,827,986 | | $ | 1,878,003 | |
| Operating netback ($/boe) | | | | | | |
| Revenue | $ | 32.71 | | $ | 69.89 | |
| Royalties | | 2.70 | | | 10.82 | |
| Operating costs | | 6.80 | | | 19.08 | |
| Transportation costs | | 2.79 | | | 3.16 | |
| Operating netback ($/boe) | $ | 20.42 | | $ | 36.83 | |
Royalties for the first quarter of 2015 were $2.70/boe, representing a 76% decrease from the first quarter of 2014 and a 72% decrease from the fourth quarter of 2014. This significant reduction is the result of the added production from 12 new horizontal wells drilled in 2014 which are subject to an 18 month Crown royalty holiday, as well as a lower Crown royalty par price in the first quarter of 2015. The Company also received a one-time retroactive rebate in royalties from the Crown as a result of a change in the royalty rate being applied to one of the Company’s higher producing wells. The Company expects to see low Crown royalties in the second quarter of 2015 resulting from low oil prices which directly impact the Crown royalty par price.
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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 on both an absolute and per boe basis for the three months ended March 31, 2015 from the comparable period in 2014. Operating costs for the first quarter of 2015 were $6.80/boe, representing decreases of 64% from the first quarter of 2014 and 42% from the fourth quarter of 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 three wells with high operating costs in order to maximize operating netbacks and cash flow for the quarter. The Company expects to see low operating costs per boe in the second quarter of 2015 as a result of continued cost control measures and efficiencies implemented in January 2015 to offset the decline in commodity prices.
Transportation costs include all costs incurred to transport emulsion and oil and gas sales to processing and distribution facilities. Transportation costs were $2.79/boe during the first quarter of 2015, which represents a decrease of 12% from the comparable quarter in 2014 and 24% from the fourth quarter of 2014. These decreases are the result of the Company’s voluntary shut-in of higher water cut wells that require trucking to processing facilities.
Operating netback for the first quarter of 2015 was $20.42/boe compared to $36.83/boe for the first quarter of 2014. This decrease is mainly due to the 53% decrease in the Company’s combined average realized price for the quarter.
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 March 31, 2015 and 2014 were $7,392 and $29,153, respectively.
Depletion and Depreciation
| | | Three Months Ended March 31 | |
| | | 2015 | | | 2014 | |
| Depletion expense | $ | 1,642,047 | | $ | 875,344 | |
| Depreciation expense | | 3,364 | | | 933 | |
| Total | $ | 1,645,411 | | $ | 876,277 | |
| $ per boe | $ | 18.38 | | $ | 17.18 | |
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 first quarter of 2015 increased by $769,134 ($1.20/boe) over the first quarter of 2014.
The significant increase in depletion expense for the first quarter of 2015 is a result of the 76% growth in the Company’s production base from the comparative quarter of 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 months March 31, 2015.
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Capital Expenditures
| | | Three Months Ended March 31 | |
| | | 2015 | | | 2014 | |
| Land and lease | $ | 7,434 | | $ | 14,592 | |
| Geological and geophysical | | 16,033 | | | 116,090 | |
| Drilling and completions | | 49,698 | | | 2,940,212 | |
| Facilities and infrastructure | | 60,124 | | | 1,221,683 | |
| Development capital | | 133,289 | | | 4,292,577 | |
| Property acquisitions | | - | | | 124,739 | |
| Disposition proceeds | | - | | | (50,000 | ) |
| Total capital expenditures(1) | $ | 133,289 | | $ | 4,367,316 | |
| Note: |
| (1) | Total capital expenditures exclude decommissioning obligations. |
The development capital spent during the first quarter of 2015 included trailing costs from capital projects that commenced in the fourth quarter of 2014, such as the build of a multi-well battery, two 3D seismic programs and completion costs for a well drilled in the Company’s fall drilling program. The Company also completed a workover on an existing well to upgrade the pump size to attain higher production levels.
Since April, oil prices have gradually improved, differentials have narrowed, and exchange rates have remained high. With these positive impacts to oil prices, Hemisphere is changing its focus from capital preservation to strategic capital investment in projects that will add production, increase reserves, and achieve long-term growth as oil prices continue to strengthen.
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 months ended March 31, 2015:
| | | Three Months Ended March 31 | |
| | | 2015 | | | 2014 | |
| Total capital expenditures | $ | 133,288 | | $ | 4,367,316 | |
| Increase in decommissioning obligations | | - | | | 30,658 | |
| Evaluation and exploration expenditures | | (22,274 | ) | | (649,098 | ) |
| Gain on disposition | | - | | | 2,942 | |
| Additions to property and equipment | $ | 111,016 | | $ | 3,751,818 | |
General and Administrative
| | | Three Months Ended March 31 | |
| | | 2015 | | | 2014 | |
| Gross general and administrative | $ | 470,902 | | $ | 427,677 | |
| Capitalized general and administrative | | (7,459 | ) | | (153,937 | ) |
| Net general and administrative | | 463,443 | | | 273,740 | |
| $ per boe | $ | 5.18 | | $ | 5.37 | |
| Share-based payments | | 219,010 | | | - | |
| Total general and administrative | | 682,453 | | | 273,740 | |
| $ per boe | $ | 7.62 | | $ | 5.37 | |
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Gross general and administrative expenses for the first quarter of 2015 increased by $43,225 over the first quarter of 2014 due to increased staffing costs and increased rental payments from the relocation of the Company’s head office.
The Company capitalizes some general and administrative expenses which can be attributed to any costs incurred during the period relating to its development and exploration activities. For the three months ended March 31, 2015, capitalized general and administrative expenses decreased by $146,478 from the comparable period in 2014. This decrease in capitalized general and administrative expenses is consistent with the Company’s reduced capital expenditures and drilling activity for the current quarter.
For the three months ended March 31, 2015 and 2014, the Company recorded share-based payments of $219,010 and $nil, respectively. This increase is the result of granting 1,325,000 incentive stock options in the first quarter of 2015, of which 25,000 will vest quarterly over a twelve month period. All share-based payments are considered to be part of the Company’s general and administrative expenses.
For the three months ended March 31, 2015, the Company realized a decrease of $0.19/boe in net general and administrative costs from the same period in 2014 as a result of increased efficiencies and production rates during the first quarter of 2015.
Finance Expense
| | | Three Months Ended March 31 | |
| | | 2015 | | | 2014 | |
| Finance expense | | | | | | |
| Interest expense | $ | 108,008 | | $ | 63,943 | |
| Part XII.6 tax | | - | | | 3,059 | |
| Accretion of provision | | 31,067 | | | 8,753 | |
| Total | $ | 139,075 | | $ | 75,755 | |
| $ per boe | $ | 1.55 | | $ | 1.49 | |
Finance expense for the first quarter of 2015 increased by $63,320 over the first quarter of 2014. This increase is a result of the increased accretion expense for the quarter, and the interest expense incurred on the Company’s outstanding bank debt which was higher in the first quarter of 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. In the first quarter of 2015, accretion expense increased by $22,314 over the comparable quarter 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
As at December 31, 2014, the Company has $47,095,101 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 current income tax in 2015. Taxes payable beyond 2015 will primarily be a function of commodity prices, capital expenditures and production volumes.
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| | | Deduction Rate | | | December 31, 2014 | | | December 31, 2013 | |
| Canadian exploration expense (CEE) | | 100% | | $ | 3,336,823 | | $ | 3,277,968 | |
| Canadian development expense (CDE) | | 30% | | | 24,371,718 | | | 9,528,985 | |
| Canadian oil and gas property expense (COGPE) | | 10% | | | 8,352,690 | | | 8,646,028 | |
| Non-capital losses carry forwards (NCL) | | 100% | | | 6,571,929 | | | 7,073,611 | |
| Undepreciated capital cost (UCC) | | 20-55% | | | 2,870,328 | | | 3,747,124 | |
| Share issuance costs and other | | Various | | | 1,591,613 | | | 1,211,572 | |
| Total | | | | $ | 47,095,101 | | $ | 33,485,288 | |
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 after tax(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-cashworking 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’saudited 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 andtransportation 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. |
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Summary of Quarterly Results
| | | 2015 | | | | | | 2014 | | | | | | | | | 2013 | | | | |
| | | Mar. 31 | | | Dec. 31 | | | Sep. 30 | | | Jun. 30 | | | Mar. 31 | | | Dec. 31 | | | Sep. 30 | | | Jun. 30 | |
| | | Q1(2) | | | Q4(3) | | | Q3(4) | | | Q2(5) | | | Q1(6) | | | Q4(7) | | | Q3(8) | | | Q2 | |
| Average daily production (boe/d) | | 995 | | | 885 | | | 725 | | | 553 | | | 567 | | | 569 | | | 461 | | | 407 | |
| Petroleum and natural gas revenue | | 2,928,264 | | | 4,568,286 | | | 4,703,496 | | | 3,799,461 | | | 3,564,036 | | | 2,958,107 | | | 3,165,562 | | | 2,375,912 | |
| Petroleum and natural gas netback | | 1,827,986 | | | 2,534,334 | | | 2,852,204 | | | 2,011,113 | | | 1,878,003 | | | 1,246,355 | | | 1,970,836 | | | 1,274,744 | |
| Funds flow from operating activities | | 1,249,142 | | | 1,334,422 | | | 2,279,842 | | | 1,550,661 | | | 1,508,107 | | | 579,824 | | | 1,570,350 | | | 847,459 | |
| Per share, basic and diluted | | 0.02 | | | 0.02 | | | 0.03 | | | 0.02 | | | 0.02 | | | 0.01 | | | 0.03 | | | 0.02 | |
| Net income (loss)(1) | | (646,345 | ) | | (3,568,603 | ) | | 720,312 | | | 554,465 | | | 626,019 | | | (1,202,692 | ) | | 673,023 | | | 80,697 | |
| Basic and diluted income (loss) per share | | (0.01 | ) | | (0.05 | ) | | 0.01 | | | 0.01 | | | 0.01 | | | (0.02 | ) | | 0.01 | | | 0.00 | |
| Combined average realized price ($/boe) | | 32.71 | | | 56.10 | | | 70.52 | | | 75.47 | | | 69.89 | | | 56.55 | | | 74.56 | | | 64.18 | |
| Operating netback ($/boe) | | 20.42 | | | 31.14 | | | 42.79 | | | 39.98 | | | 36.83 | | | 23.83 | | | 46.42 | | | 34.44 | |
| Notes: |
| (1) | Certain quarterly amounts were restated retrospectively due to a change in accounting policy as disclosed in Note 4 of the Company’saudited annual financial statements for the year ended December 31, 2014. |
| (2) | The decreases in net income, funds flow from operations and petroleum and natural gas netbacks for this quarter can be attributed to thedecrease in the Company’s combined average realized price resulting from the decline in oil prices. |
| (3) | A significant portion of the loss in this quarter is due to the $2,702,925 recorded in property impairment and an increase in depletionexpense as a result of a change in the Company’s depletion accounting policy. |
| (4) | The net income for this quarter can be attributed to a combination of the increase in the Company’s production from its summer drillingprogram and the improvement of netback resulting from decreased operating and transportation costs. |
| (5) | The improvement in net income for this quarter over certain prior quarters is primarily due to the Company’s increase in the combinedaverage realized price resulting in higher operating netback. |
| (6) | The improvement in net income for this quarter is primarily due to the Company’s increased production levels from the drilling of three newwells and an increase in combined average realized price. |
| (7) | A significant portion of the net loss in this quarter is due to the increase in depletion expense as a result of the Company’s increase inproduction. |
| (8) | The high net income in this quarter is primarily due to the Company’s increased production levels and average realized price for thequarter. |
The quarterly figures above for the current and previous fiscal years are all presented with the application of IFRS.
Outstanding Share Capital
| | | May 27, 2015 | | | March 31, 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 March 31, 2015, there were no events that would have impacted the Company’s share capital.
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The Company has the following stock options that are outstanding and exercisable as at May 27, 2015:
| | | | | | Balance Outstanding | | | Balance Exercisable | |
| Exercise Price | | Expiry Date | | | May 27, 2015 | | | May 27, 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 | | | 1,200,000 | |
| $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 March 31, 2015 and December 31, 2014 were $10,420,007 and $11,644,609, respectively, representing a decrease in net debt of $1,224,602.
The Company’s cash provided by financing activities for the three months ended March 31, 2015 and 2014 were $108,750 and $28,125, respectively. In the first quarter of 2015, the Company issued 435,000 common shares through the exercise of incentive stock options at an exercise price of $0.25 each for gross proceeds of $108,750.
| | | | As at | |
| | | | March 31, 2015 | | | December 31, 2014 | |
| | Shareholders’ equity | $ | 30,373,651 | | $ | 30,692,235 | |
| | Undrawn component of bank credit facilities | | 5,026,665 | | | 7,815,853 | |
| | Total capital | $ | 35,400,316 | | $ | 38,508,088 | |
The Company has a demand operating credit facility in the amount of $15,000,000 with Alberta Treasury Branches. 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.
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| 12 | Q1 2015 MANAGEMENT’S DISCUSSION & ANALYSIS |
At March 31, 2015, the Company has drawn a total of $9,973,336 from its credit facility (December 31, 2014 - $7,184,147) and was in compliance with the above financial covenant. The Company is currently undergoing its annual review.
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.
Related Party Transactions
During the first quarter of 2015, the Company paid $10,000 in director fees. 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 March 31 | |
| | | 2015 | | | 2014 | |
| Short-term benefits | $ | 205,000 | | $ | 157,500 | |
| Share-based payments | | 135,660 | | | - | |
Short-term benefits, which are primarily salaries and wages, have increased during the first quarter of 2015 compared to the first quarter of 2014 mainly as the result of a technical consultant who transitioned to full-time employment in September 2014.
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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 | $ | 143,420 | | $ | 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.
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
The Company’s management is conducting an evaluation of the effectiveness of the Company’s disclosure controls and procedures ("DC&P"), as defined in National Instrument 52-109Certification 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 initial evaluation, the Company’s CEO and CFO have concluded that as a result of the material weaknesses in the internal controls over financial reporting as disclosed in the section below, the Company’s disclosure controls and procedures were not 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 will include 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. The assessment is being based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO 2013").
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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 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. Internal controls over financial reporting 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 internal controls over financial reporting, 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.
Management, with the participation of the Company’s CEO and CFO, is conducting an evaluation of the Company’s internal controls over financial reporting. Based on its initial assessment, management has concluded that the Company’s internal controls over financial reporting were not effective as management identified material weaknesses with respect 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.
The Company is currently in the process of enhancing the internal controls over financial reporting in order to remediate these material weaknesses.
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 March 31, 2015, the Company's financial instruments include accounts receivable, reclamation deposits, bank indebtedness, accounts payable and accrued liabilities.
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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 atwww.hemisphereenergy.ca or on SEDAR atwww.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.
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.
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The maximum exposure to credit risk is as follows:
| | | As at | |
| | | March 31, 2015 | | | December 31, 2014 | |
| Accounts receivable | | | | | | |
| Trade receivables | $ | 1,103,127 | | $ | 1,041,843 | |
| Receivables from joint venture | | 80,019 | | | 95,355 | |
| Reclamation deposits | | 105,535 | | | 105,535 | |
| Total | $ | 1,288,681 | | $ | 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 March 31, 2015, the Company had net debt of $10,420,007 (December 31, 2014 - $11,644,609), which includes bank indebtedness of $9,973,336 (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.
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.
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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.
| | a) | 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. |
A reconciliation of funds flow from operations to cash provided by operating activities is presented as follows:
| | | | Three Months Ended March 31 | |
| | | | 2015 | | | 2014 | |
| | Cash provided by operating activities | $ | 828,152 | | $ | 800,534 | |
| | Change in non-cash working capital | | 420,990 | | | 707,573 | |
| | Funds flow from operations | $ | 1,249,142 | | $ | 1,508,107 | |
| | Funds flow from operations per share, basic and diluted | $ | 0.02 | | $ | 0.02 | |
| | 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. |
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| | 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 the future growth of the Company. 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 | |
| | | | March 31, 2015 | | | December 31, 2014 | |
| | Current assets | $ | 1,294,578 | | $ | 1,437,181 | |
| | Current liabilities(1) | | (1,741,249 | ) | | (5,897,643 | ) |
| | Bank indebtedness | | (9,973,336 | ) | | (7,184,147 | ) |
| | Net debt | $ | (10,420,007 | ) | $ | (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 ("NI 51-101").
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.
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.
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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 atwww.hemisphereenergy.caor on SEDAR atwww.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 |
