| 5 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
MANAGEMENT’S DISCUSSION AND ANALYSIS
Dated as at April 21, 2015
The following Management’s Discussion and Analysis ("MD&A") is a review of the operations and current financial position for the year ended December 31, 2014 for Hemisphere Energy Corporation ("Hemisphere" or the "Company") and should be read in conjunction with the audited annual financial statements and related notes as at and for the years ended December 31, 2014 and 2013. 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 audited annual financial statements which were prepared in accordance with International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board ("IASB").
This MD&A contains non-IFRS measurements and forward-looking statements. Readers are cautioned that this document should be read in conjunction with Hemisphere’s disclosure under “Non-IFRS Measurements” 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.
During the year, Hemisphere successfully drilled two horizontal oil wells and one vertical exploration well in Jenner. The Company also completed a 3D seismic survey in the fourth quarter of 2014.
The Company expanded its landholdings during the year through Crown land sales, acquiring a total of 10 sections (6,400 acres) in the surrounding Jenner area. The Company also completed a small acquisition, which included 1.75 sections (1,120 acres) in the Jenner area.
Atlee Buffalo, Alberta
The Company operates 100% of its wells in the Atlee Buffalo area. The property is accessible year-round and is located in close proximity to the Company’s Jenner property in southeastern Alberta. Hemisphere has a 92% 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 and farm-ins.
| Hemisphere Energy Corporation |
| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 6 |
During the year, the Company executed three successful drilling programs in Atlee Buffalo that resulted in 10 horizontal oil wells being placed on production. The addition of these wells in 2014 resulted in significant production, reserve and cash flow growth over the previous year. The Company also shot a substantial 3D seismic program in Atlee Buffalo during the fourth quarter of 2014 to assist in drilling future locations within the area.
The Company closed an acquisition in the Atlee Buffalo area which included an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to the Company’s existing land base. Additionally, the Company expanded its landholdings during the year through Crown land sales, acquiring a total of 1.75 sections (1,120 acres) in the surrounding Atlee Buffalo area.
Operating Results
The Company generated funds flow from operations of $6,673,033 ($0.10/share) for the year ended December 31, 2014, as compared to $3,789,202 ($0.07/share) for the year ended December 31, 2013. For the fourth quarter of 2014, the Company generated funds flow from operations of $1,334,422 ($0.02/share) as compared to $579,824 ($0.01/share) for the fourth quarter of 2013.
The Company realized an increase in funds flow from operations for the three months and year ended December 31, 2014 of 130% and 76%, respectively, over the comparable periods in 2013. This is primarily from the Company’s increased revenues associated with the production from wells drilled during 2014, in addition to lower operating costs.
The Company reported a net loss of $1,667,807 ($0.02/share), which included a deferred tax expense of $129,552, for the year ended December 31, 2014 compared to a net loss of $510,266 ($0.01/share) for the year ended December 31, 2013, which included a deferred tax recovery of $357,573. For the three months ended December 31, 2014 and 2013, the Company reported a net loss of $3,568,603 ($0.05/share) and $1,202,692 ($0.02/share), respectively, which includes the deferred tax adjustments.
Production
| | | Three Months Ended December 31 | | | Year Ended December 31 | |
| By product: | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
| Oil (bbl/d) | | 763 | | | 443 | | | 583 | | | 381 | |
| Natural gas (Mcf/d) | | 720 | | | 746 | | | 593 | | | 474 | |
| NGL (bbl/d) | | 3 | | | 2 | | | 2 | | | 3 | |
| Total (boe/d) | | 885 | | | 569 | | | 683 | | | 463 | |
| Oil and NGL weighting | | 86% | | | 78% | | | 86% | | | 83% | |
In the fourth quarter of 2014, the Company’s average daily production increased to a record 885 boe/d (86% oil and NGL) which represents an increase of 56% over the fourth quarter of 2013 and 22% over the third quarter of 2014. The Company’s average daily production for the year ended December 31, 2014 increased by 48% over 2013 to 683 boe/d (86% oil and NGL).
In the fourth quarter of 2014, the Company had a 72% increase in average daily oil production over the fourth quarter of 2013. The Company’s average daily oil production for the year ended December 31, 2014 increased by 53% over 2013 to 583 bbl/d. These increases can be attributed to the successful development of the Company’s Atlee Buffalo and Jenner properties which resulted in 12 new producing oil wells during the year, four of which came on production in the fourth quarter of 2014.
| Hemisphere Energy Corporation |
| 7 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
Average Benchmark and Realized Prices
| | Three Months Ended December 31 | | | Year Ended December 31 | |
�� | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
Benchmark Prices | | | | | | | | | | | | |
WTI (US$/bbl)(1) | $ | 73.15 | | $ | 97.46 | | $ | 93.00 | | $ | 97.98 | |
Exchange rate (1 US$/C$) | | 1.1361 | | | 1.0522 | | | 1.1045 | | | 1.0301 | |
WTI (C$/bbl) | | 83.10 | | | 102.55 | | | 102.71 | | | 100.93 | |
WCS (C$/bbl)(2) | | 66.77 | | | 68.44 | | | 81.11 | | | 74.93 | |
AECO natural gas ($/Mcf)(3) | | 3.57 | | | 3.46 | | | 4.41 | | | 3.07 | |
Average realized prices | | | | | | | | | | | | |
Crude oil ($/bbl) | | 61.66 | | | 65.70 | | | 73.87 | | | 71.19 | |
Natural gas ($/Mcf) | | 3.52 | | | 3.99 | | | 4.08 | | | 3.45 | |
NGL ($/bbl) | | 39.72 | | | 64.21 | | | 54.85 | | | 68.60 | |
Combined ($/boe) | $ | 56.10 | | $ | 56.55 | | $ | 66.68 | | $ | 62.55 | |
| 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.
The Company’s combined average realized price for the fourth quarter of 2014 decreased slightly by $0.45/boe to $56.10/boe over the fourth quarter of 2013. This decrease can be attributed to the decline in oil prices during the fourth quarter of 2014, which also decreased the Company’s average realized crude oil price by $4.04/bbl as compared to the fourth quarter of 2013. This recent decline in oil prices has been the result of an oversupply of oil in the global market. It is expected that high North American crude oil inventories and continued production growth may continue to suppress domestic oil prices into the second half of 2015.
For the year ended December 31, 2014, the Company’s combined average realized price increased to $66.68/boe from $62.55/boe in 2013. The Company’s average realized oil price was $73.87/bbl for the year ended December 31, 2014, representing an increase of $2.68/bbl over 2013. This increase is a reflection of strong WTI pricing and a narrow Western Canadian Select ("WCS") oil differential in the first three quarters of 2014. Also, given that North American crude oil benchmark market prices are denominated in USD, a decrease in the value of the Canadian dollar compared to the USD in 2014 has had a positive impact on the Company’s average realized oil price and revenues for the year ended December 31, 2014.
The Company’s average realized natural gas price decreased in the fourth quarter of 2014 by $0.47/Mcf over the same quarter of 2013. The Company’s average realized natural gas price for the year ended December 31, 2014 increased by $0.63/Mcf over the comparable 2013 year.
| Hemisphere Energy Corporation |
| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 8 |
Revenue
| | | Three Months Ended December 31 | | | Year Ended December 31 | |
| | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
| Oil | $ | 4,326,223 | | $ | 2,674,513 | | $ | 15,717,054 | | $ | 9,903,388 | |
| Natural gas | | 232,914 | | | 273,702 | | | 883,776 | | | 596,881 | |
| NGL | | 9,149 | | | 9,892 | | | 34,449 | | | 72,929 | |
| Total | $ | 4,568,286 | | $ | 2,958,107 | | $ | 16,635,279 | | $ | 10,573,199 | |
Revenue for the fourth quarter of 2014 increased substantially by 54% over the comparable quarter of 2013 despite decreases in average realized commodity prices for the quarter. The increase in revenue can be directly attributed to the 56% increase in production associated with the Company’s increased drilling activity in the fourth quarter of 2014.
Revenue for the year ended December 31, 2014 was $16,635,279, which represents a 57% increase over the comparable 2013 year. This increase in revenue is consistent with the growth in production as a result of the Company’s drilling programs in the Jenner and Atlee Buffalo areas, as well as the increase in average realized crude oil and combined prices for the year.
Operating Netback
| | | Three Months Ended December 31 | | | Year Ended December 31 | |
| | 2014 | | | 2013 | | | 2014 | | | 2013 | |
Operating netback | | | | | | | | | | | | |
Revenue | $ | 4,568,286 | | $ | 2,958,107 | | $ | 16,635,279 | | $ | 10,573,199 | |
Royalties | | 783,898 | | | 563,642 | | | 3,008,377 | | | 1,898,532 | |
Operating costs | | 948,519 | | | 979,232 | | | 3,516,956 | | | 2,558,945 | |
Transportation costs | | 301,535 | | | 168,878 | | | 834,292 | | | 508,230 | |
Operating netback | $ | 2,534,334 | | $ | 1,246,355 | | $ | 9,275,653 | | $ | 5,607,492 | |
Operating netback ($/boe) | | | | | | | | | | | | |
Revenue | $ | 56.10 | | $ | 56.55 | | $ | 66.68 | | $ | 62.55 | |
Royalties | | 9.60 | | | 10.78 | | | 12.05 | | | 11.23 | |
Operating costs | | 11.65 | | | 18.72 | | | 14.10 | | | 15.14 | |
Transportation costs | | 3.70 | | | 3.23 | | | 3.34 | | | 3.01 | |
Operating netback ($/boe) | $ | 31.15 | | $ | 23.82 | | $ | 37.19 | | $ | 33.17 | |
Royalties for the fourth quarter of 2014 were $9.60/boe, representing a decrease in royalties of 11% over the fourth quarter of 2013 and 28% over the third quarter of 2014. These decreases can be attributed to Atlee Buffalo’s increased production during the quarter which has the lowest royalty rate per boe of all of the Company’s properties. This is a result of the 10 new wells drilled in Atlee Buffalo which are subject to a royalty holiday, in addition to lower overriding royalties on lands in the area. Royalties for the year ended December 31, 2014 increased by $0.82/boe over the 2013 year. This increase can be attributed to six Jenner oil wells coming off of their royalty holiday in 2014, and that the majority of the Company’s 2014 production was from Jenner which has the highest per boe royalty rate. The Company expects to see lower Crown royalties in the first half of 2015 as a result of the recent decline in oil price which directly impacts the Crown royalty par price.
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 increased on an absolute basis for both the three months and year ended December 31, 2014 over their comparable periods in 2013 as a result of increases in production from the drilling of new wells. Operating costs for the fourth quarter of 2014 were $11.65/boe, representing a decrease of 38% from the fourth quarter of 2013. For the year ended December 31, 2014, operating costs were $14.10/boe, representing a decrease of 7% over 2013. These decreases are the result of higher production levels in Atlee Buffalo, which have lower operating costs per boe as well as realized economies of scale as a result of drilling new wells in 2014. The Company has also reduced the amount of produced water that is processed at third-party facilities, which is subject to processing fees, in order to reduce operating costs. The Company expects to see lower operating costs per boe in the first half of 2015 due to the implementation of cost control measures and efficiencies that were put into place in January 2015.
| Hemisphere Energy Corporation |
| 9 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
Transportation costs include all costs incurred to transport emulsion and oil and gas sales to processing and distribution facilities. Transportation costs for the fourth quarter of 2014 were $3.70/boe, which represents an increase of 15% over the comparable quarter in 2013. For the year ended December 31, 2014, transportation costs increased by 11% over 2013. These increases can be attributed to the addition of 10 new Atlee Buffalo horizontal wells during 2014 which have higher transportation costs associated with trucking production volumes to processing facilities and sales points.
Operating netback for the fourth quarter of 2014 was $31.15/boe, representing a 31% increase over the comparable quarter of 2013. This increase is in large part due to the 38% decrease in the Company’s operating costs and 11% decrease in royalties for the quarter. Operating netback for the year ended December 31, 2014 also increased by 12% to $37.19/boe over 2013.
Exploration and Evaluation
Exploration and evaluation expense generally consists of certain geological and geophysical costs, expiry of undeveloped lands, and costs of uneconomic exploratory wells. Exploration and evaluation expenses for the year ended December 31, 2014 increased to $190,887 from $116,006 for the year ended December 31, 2013.
Depletion and Depreciation
| | | Three Months Ended December 31 | | | Year Ended December 31 | |
| | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
| Depletion expense | $ | 2,412,265 | | $ | 1,285,690 | | $ | 5,353,585 | | $ | 3,729,169 | |
| Depreciation expense | | 2,401 | | | 1,006 | | | 7,404 | | | 4,524 | |
| Total | $ | 2,414,666 | | $ | 1,286,696 | | $ | 5,360,989 | | $ | 3,733,693 | |
| $ per boe | $ | 47.96 | | $ | 24.60 | | $ | 21.49 | | $ | 22.09 | |
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 fourth quarter of 2014 increased by $1,127,970 ($23.36/boe) over the fourth quarter of 2013. For the years ended December 31, 2014 and 2013, depletion and depreciation expenses were $5,360,989 and $3,733,693, respectively.
The significant increases in depletion expense are a result of the Company changing its accounting for depleting its petroleum and natural gas properties. With the acquisition of the Company’s core Jenner and Atlee Buffalo properties, the value of its Proved plus Probable reserves increased substantially. These acquisitions, in combination with the Company’s increased access to capital through additional equity financings and banking facilities, have expanded the Company’s ability to further the development of exploration assets and Probable reserves. As a result, the Company changed from using the unit-of-production method based solely on production volumes in relation to total estimated Proved reserves to now include total estimated Proved and Probable reserves.
| Hemisphere Energy Corporation |
| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 10 |
Capital Expenditures
| | | Three Months Ended December 31 | | | Year Ended December 31 | |
| | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
Land and lease | $ | 46,356 | | $ | 121,082 | | $ | 311,092 | | $ | 117,274 | |
Geological and geophysical | | 1,080,890 | | | 182,595 | | | 1,747,813 | | | 368,116 | |
Drilling and completions | | 3,923,713 | | | 297,614 | | | 13,254,809 | | | 2,476,925 | |
Investment in facilities | | 1,880,248 | | | 2,009,627 | | | 5,370,943 | | | 3,914,804 | |
Development capital | | 6,931,208 | | | 2,610,918 | | | 20,684,657 | | | 6,877,119 | |
Property acquisitions | | - | | | 2,981,617 | | | 634,739 | | | 3,092,055 | |
Fixed assets | | - | | | - | | | 46,970 | | | - | |
Disposition proceeds | | - | | | - | | | (50,000 | ) | | - | |
Total capital expenditures(1) | $ | 6,931,208 | | $ | 5,592,535 | | $ | 21,316,366 | | $ | 9,969,174 | |
| Note: |
| (1) | Total capital expenditures exclude decommissioning obligations. |
The development capital spent during the fourth quarter of 2014 includes $3,923,713 on the drilling and completion of five wells as part of the Company’s fall drilling program. Investment in facilities of $1,880,248 includes multi-well battery costs for the new wells drilled in the fall drilling program, upgrades to a gas pipeline in the Atlee Buffalo area and equipment purchases for the Company’s main Jenner facility. The Company also spent additional capital on geological and geophysical activities in the fourth quarter of 2014 which included two 3D seismic programs, one in Atlee Buffalo and one in Jenner, to evaluate future drilling locations and reserve potential in the areas.
The development capital spent during the year ended December 31, 2014 increased by $13,807,538 over the comparable 2013 year. This increase can be attributed to significantly more activity during 2014 including drilling 13 wells, construction of two multi-well batteries and multiple pipelines in Atlee Buffalo, equipment upgrades and replacements, and the installation of a solution gas compressor at the main production facility in Jenner. During the year, the Company closed an acquisition in the Atlee Buffalo area for proceeds of $510,000, which included an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to the Company’s existing land base. The Company also closed a small acquisition in the surrounding Jenner area and disposed of a vertical treater from its Jenner facility.
The following table is a reconciliation of the Company’s capital expenditures to the additions of property and equipment as shown in Note 9 of the Company’s audited annual financial statements for the years ended December 31, 2014 and 2013:
| | Three Months Ended December 31 | | | Year Ended December 31 | |
| | 2014 | | | 2013 | | | 2014 | | | 2013 | |
Total capital expenditures | $ | 6,931,208 | | $ | 5,592,535 | | $ | 21,316,366 | | $ | 9,969,174 | |
Increase in decommissioning obligations | | 3,017,794 | | | 1,504,143 | | | 3,099,549 | | | 1,537,533 | |
Evaluation and exploration expenditures | | (158,982 | ) | | 62,844 | | | (1,889,545 | ) | | (1,418,557 | ) |
Gain on disposition | | - | | | 3,889 | | | 2,942 | | | 3,889 | |
Change in unproved properties | | - | | | (52,845 | ) | | - | | | - | |
Additions to property and equipment | $ | 9,790,020 | | $ | 7,110,566 | | $ | 22,529,311 | | $ | 10,092,039 | |
| Hemisphere Energy Corporation |
| 11 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
General and Administrative
| | | Three Months Ended December 31 | | | Year Ended December 31 | |
| | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
Gross G&A | $ | 1,174,466 | | $ | 718,597 | | $ | 2,674,693 | | $ | 1,804,072 | |
Share-based payments | | (15,394 | ) | | 295,394 | | | 452,780 | | | 360,464 | |
Capitalized G&A | | (128,901 | ) | | (183,184 | ) | | (472,530 | ) | | (287,159 | ) |
Total | $ | 1,030,171 | | $ | 830,807 | | $ | 2,654,943 | | $ | 1,877,376 | |
$ per boe | $ | 12.65 | | $ | 15.88 | | $ | 10.64 | | $ | 11.11 | |
Gross general and administrative expenses for the three months ended December 31, 2014 increased by $455,870 over the three months ended December 31, 2013. For the year ended December 31, 2014, gross general and administrative expenses increased by $870,621 over the comparable 2013 year. These increases can be attributed to increased staff, technical consulting fees, investor relations activities, travel expenses, professional fees, and office expenses due to 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 year relating to its development and exploration activities. For the year ended December 31, 2014, capitalized general and administrative expenses increased by $185,371 over the comparable 2013 year. This increase is consistent with the Company’s drilling programs and capital projects for the year.
For the years ended December 31, 2014 and 2013, the Company recorded share-based payments of $452,780 and $360,464, respectively. These increases are the result of granting additional incentive stock options in 2014, as well as a higher stock price volatility and interest rate which are assumptions used in the Black-Scholes valuation of the options. All share-based payments are considered to be part of the Company’s general and administrative expenses.
For the year ended December 31, 2014, the Company realized a decrease of $0.46/boe in total general and administrative costs from 2013 as a result of increased efficiencies and production rates in 2014.
Impairment of Property and Equipment
The significant decline in crude oil and natural gas prices in the fourth quarter of 2014 was recognized by the Company as an indicator of impairment at year-end. The Company performed an impairment test on its petroleum and natural gas assets and it was determined that the carrying amount of three cash-generating units ("CGUs") exceeded their recoverable amount. Accordingly, the Company recognized an impairment charge of $2,702,925 for the year ended December 31, 2014 as compared to $556,371 for the year ended December 31, 2013.
The recoverable amounts of the CGUs were determined with fair value less costs to sell based on expected future cash flows from Proved plus Probable reserve value, using discount rates specific to the underlying composition of assets residing in each CGU. The pre-tax discount rates ranged from 10% to 15% depending on the nature of the reserves. The Company also changed its impairment test to include Proved and Probable reserves of all properties to maintain consistency with its depletion policy.
| Hemisphere Energy Corporation |
| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 12 |
Finance Expense
| | | Three Months Ended December 31 | | | Year Ended December 31 | |
| | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
Finance expense | | | | | | | | | | | | |
Interest expense | $ | 54,794 | | $ | 61,108 | | $ | 197,682 | | $ | 189,262 | |
Part XII.6 tax | | 581 | | | - | | | 11,889 | | | - | |
Accretion of provision | | 40,516 | | | 1,628 | | | 66,776 | | | 6,513 | |
Total finance expense | $ | 95,891 | | $ | 62,736 | | $ | 276,347 | | $ | 195,775 | |
Finance expense for the three months and year ended December 31, 2014 increased by $33,155 and $80,572, respectively, over the comparable periods in 2013. These increases are primarily the result of the part XII.6 tax incurred on unspent flow-through expenditures and increased accretion expense for the periods.
For the three months and year ended December 31, 2014, the Company recorded $581 and $11,889, respectively, in part XII.6 tax. This part XII.6 tax is accumulated on the Company’s unspent balance of flow-through expenditures at the end of the period. The Company’s required obligation was to incur qualified expenditures of $2,000,050 by December 31, 2014 in connection with the Company’s flow-through private placement which closed on December 10, 2013.
Accretion expense represents the adjusted present value of the Company’s decommissioning obligations which include the abandonment and reclamation costs associated with wells and facilities. For the three months and year ended December 31, 2014, accretion expense was $40,516 and $66,776, respectively. Accretion expense increased for the three months and year ended December 31, 2014 over the comparable periods of 2013 due to the decommissioning obligations associated with the new wells acquired in 2014, as well as those new wells drilled in the Jenner and Atlee Buffalo areas. The Company changed its estimate of decommissioning obligations by using the information as set by the Alberta Energy Regulator ("AER") in Directive 011, as its primary source of estimating future abandonment and reclamation costs.
Flow-through Share Premium Recovery
In connection with the flow-through private placement completed on December 10, 2013, the Company fulfilled its obligation to incur qualified expenditures of $2,000,050 by December 31, 2014. The qualified expenditures were spent on two 3D seismic programs in the Jenner and Atlee Buffalo areas as well as the drilling of a vertical test well in Jenner. At December 31, 2014, the balance in flow-through premium liability has been reduced to nil and transferred to flow-through share premium recovery.
Deferred Taxes
At December 31, 2014, the Company recorded a deferred tax asset of $1,641,916 (December 31, 2013 - $1,532,405).
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.
| Hemisphere Energy Corporation |
| 13 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
| | 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 | |
Restatement of Previously Reported Results
The Company has restated certain financial information for the year ended December 31, 2013 (the "2013 Restatement") which has been disclosed in Note 4 of the Company’s audited annual financial statements for the year ended December 31, 2014.
The material changes included in the 2013 Restatement affect the Company’s impairment, depletion, and decommissioning costs and will have a positive impact, significantly reducing the Company’s loss in December 2013 by $3.3 million from $3.8 million to $0.5 million.
As a result of the adjustment of impairment and depletion costs due to the effects of IFRS and a change in accounting policy applied retrospectively, Hemisphere’s petroleum and natural gas interests increased by $4.0 million. In addition, Hemisphere has incorporated the AER’s updated decommissioning directive, which resulted in an increase in decommissioning liability of $0.7 million. The 2013 Restatement affects only non-cash items and therefore has no impact on cash flow.
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(1) | | | December 31, 2012(1) | |
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(2) | | 6,673,033 | | | 3,789,202 | | | 3,265,657 | |
Per share, basic and diluted | | 0.10 | | | 0.07 | | | 0.06 | |
Net income (loss) after tax | | (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)(4) | | 37.19 | | | 33.17 | | | 37.33 | |
Capital expenditures, including property acquisitions | | 21,316,366 | | | 9,969,174 | | | 11,888,398 | |
Net debt(3) | | (11,644,609 | ) | | (6,330,906 | ) | | (3,927,595 | ) |
Bank indebtedness | | 7,184,147 | | | 4,500,000 | | | 1,035,000 | |
Total assets | | 48,951,632 | | | 32,195,577 | | | 24,486,865 | |
Total non-current liabilities | $ | 5,177,607 | | $ | 2,011,282 | | $ | 467,235 | |
| Notes: |
| (1) | Certain amounts were restated retrospectively 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 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. |
| (3) | Net debt is a non-IFRS measure calculated as current assets minus current liabilities including bank indebtedness and excluding flow-through share premium. |
| (4) | Operating netback is a non-IFRS measure calculated as the Company’s oil and gas sales, less royalties, operating expensesand transportation costs per barrel of oil equivalent. |
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| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 14 |
Summary of Quarterly Results(1)
| | | 2014 | | | 2013 | |
| | | Dec. 31 | | | Sep. 30 | | | Jun. 30 | | | Mar. 31 | | | Dec. 31 | | | Sep. 30 | | | Jun. 30 | | | Mar. 31 | |
| | | Q4(2) | | | Q3(3) | | | Q2(4) | | | Q1(5) | | | Q4(6) | | | Q3(7) | | | Q2 | | | Q1 | |
Average daily production (boe/d) | | 885 | | | 725 | | | 553 | | | 567 | | | 569 | | | 461 | | | 407 | | | 414 | |
Petroleum and natural gas revenue | | 4,568,286 | | | 4,703,496 | | | 3,799,461 | | | 3,564,036 | | | 2,958,107 | | | 3,165,562 | | | 2,375,912 | | | 2,073,617 | |
Petroleum and natural gas netback | | 2,534,334 | | | 2,852,204 | | | 2,011,113 | | | 1,878,003 | | | 1,246,355 | | | 1,970,836 | | | 1,274,744 | | | 1,115,557 | |
Funds flow from operating activities | | 1,334,422 | | | 2,279,842 | | | 1,550,661 | | | 1,508,107 | | | 579,824 | | | 1,570,350 | | | 847,459 | | | 791,568 | |
Per share, basic and diluted | | 0.02 | | | 0.03 | | | 0.02 | | | 0.02 | | | 0.01 | | | 0.03 | | | 0.02 | | | 0.01 | |
Net income (loss) | | (3,568,603 | ) | | 720,312 | | | 554,465 | | | 626,019 | | | (1,202,692 | ) | | 673,023 | | | 80,697 | | | (61,295 | ) |
Basic and diluted income (loss) per share | | (0.05 | ) | | 0.01 | | | 0.01 | | | 0.01 | | | (0.02 | ) | | 0.01 | | | 0.00 | | | (0.00 | ) |
Combined average realized price ($/boe) | | 56.10 | | | 70.52 | | | 75.47 | | | 69.89 | | | 56.55 | | | 74.56 | | | 64.18 | | | 55.66 | |
Operating netback ($/boe) | | 31.14 | | | 42.79 | | | 39.98 | | | 36.83 | | | 23.83 | | | 46.42 | | | 34.44 | | | 29.95 | |
| Notes: |
| (1) | Certain quarterly amounts were restated retrospectively as disclosed in Note 4 of the Company’s audited annual financial statements for the year ended December 31, 2014. |
| (2) | A significant portion of the loss in this quarter 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. |
| (3) | The income for this quarter 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. |
| (4) | The improvement in income for this quarter over certain prior quarters is primarily due to the Company’s increase in the combined average realized price resulting in higher operating netback. |
| (5) | The improvement in income for this quarter 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. |
| (6) | A significant portion of the loss in this quarter is due to the increase in depletion expense as a result of a change in the Company’s depletion accounting policy. |
| (7) | The high income in this quarter is primarily due to the Company’s increased production levels and average realized price for the quarter. |
The quarterly figures above for the current and previous fiscal years are all presented with the application of IFRS.
Outstanding Share Data
| | | April 21, 2015 | | | December 31, 2014 | | | December 31, 2013 | |
| Fully diluted share capital | | | | | | | | | |
| Common shares issued and outstanding | | 75,803,498 | | | 75,368,498 | | | 61,307,498 | |
| Share purchase warrants | | - | | | - | | | 9,245,879 | |
| Stock options | | 6,860,000 | | | 5,970,000 | | | 5,680,000 | |
| Total fully diluted | | 82,663,498 | | | 81,338,498 | | | 76,233,377 | |
Subsequent to December 31, 2014, the following events impacted the Company’s share capital:
| • | On January 29, 2015, the Company granted incentive stock options to officers, directors, employees and consultants of the Company entitling them to purchase up to a total of 1,225,000 common shares at an exercise price of $0.24 each. |
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| 15 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
| • | In February and March 2015, the Company received proceeds of $108,750 for the exercise of 435,000 incentive stock options with an exercise price of $0.25. |
| | |
| • | On March 1, 2015, the Company issued 100,000 incentive stock options to a consultant of the Company with an exercise price of $0.39. |
The Company has the following stock options that are outstanding and exercisable as at April 21, 2015:
| | | | | | Balance Outstanding & | |
| Exercise Price | | Expiry Date | | | Exercisable April 21, 2015 | |
| $0.26 | | 30-Sep-15 | | | 490,000 | |
| $0.30 | | 23-Dec-15 | | | 375,000 | |
| $0.30 | | 27-Jan-16 | | | 200,000 | |
| $0.38 | | 9-Feb-16 | | | 50,000 | |
| $0.40 | | 26-May-16 | | | 475,000 | |
| $0.48 | | 5-Jul-16 | | | 50,000 | |
| $0.70 | | 8-Feb-17 | | | 1,500,000 | |
| $0.65 | | 24-Apr-17 | | | 75,000 | |
| $0.61 | | 5-Jul-17 | | | 425,000 | |
| $0.50 | | 8-Mar-18 | | | 250,000 | |
| $0.55 | | 6-Jan-19 | | | 660,000 | |
| $0.65 | | 29-Sep-19 | | | 785,000 | |
| $0.61 | | 7-Oct-19 | | | 200,000 | |
| $0.24 | | 29-Jan-20 | | | 1,225,000 | |
| $0.39 | | 1-Mar-20 | | | 100,000 | |
| | | | | | 6,860,000 | |
| Weighted-average exercise price | | $ | 0.49 | |
Liquidity and Capital Management
The Company’s net debt as at December 31, 2014 and 2013 was $11,644,609 and $6,330,906, respectively, representing an increase in net debt of $5,313,703.
The Company’s cash provided by financing activities for the years ended December 31 2014 and 2013 were $9,329,628 and $3,795,550, respectively.
The following occurred during the year ended December 31, 2014:
| • | On May 14, 2014, the Company closed a bought-deal equity financing consisting of 13,333,500 common shares at a price of $0.75 per common share for aggregate gross proceeds of $10,000,125. |
| | | |
| • | The Company issued 690,000 common shares for the exercise of incentive stock options at various prices for gross proceeds of $220,850. Additionally, the Company issued 37,500 common shares from the exercise of share purchase warrants at a price of $0.75 for gross proceeds of $28,125. |
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| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 16 |
The following occurred during the year ended December 31, 2013:
| • | On January 25, 2013, the Company closed the second and final tranche of a private placement consisting of 86,900 units at a price of $0.65 per unit for gross proceeds of $56,485. |
| | | |
| • | On December 9, 2013, the Company closed a bought deal financing consisting of 4,182,550 units at a price of $0.55 per unit and 3,077,000 common shares to be issued on a flow-through basis at a price of $0.65 per flow-through share for aggregate gross proceeds of $4,300,453. |
| | | | December 31, 2014 | | | December 31, 2013 | |
| | Shareholders’ equity | $ | 30,692,235 | | $ | 22,338,570 | |
| | Undrawn component of bank credit facilities | | 7,815,853 | | | 6,000,000 | |
| | Total capital | $ | 38,508,088 | | $ | 28,338,570 | |
On November 28, 2014, the Company increased its total credit facilities with Alberta Treasury Branches from $10,500,000 to $15,000,000, of which $7,184,147 was drawn at December 31, 2014 (December 31, 2013 - $4,500,000). 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-draw funds. The Company’s next annual review is scheduled to occur in May 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.
Related Party Transactions
During the fourth quarter of 2014, the Company paid $10,000 in director fees. For the year ended December 31, 2014, the Company paid $40,000 in director fees. These fees were charged for services provided by the Chairman of the Company’s Board of Directors.
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| 17 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
Compensation to key executive personnel, consisting of the Company’s officers, directors and Chairman, was paid as follows:
| | | Three Months Ended December 31 | | | Year Ended December 31 | |
| | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
| Short-term benefits | $ | 502,500 | | $ | 315,000 | | $ | 986,666 | | $ | 750,000 | |
| Share-based payments | | 49,723 | | | 125,808 | | | 377,743 | | | 125,808 | |
Short-term benefits, which are primarily salaries and wages, have increased during the year ended December 31, 2014 as compared to 2013 as the result of a technical consultant who transitioned to full-time employment in September 2014.
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
The Company’s significant accounting estimates 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 annual financial statements.
The preparation of these audited annual 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.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected. Critical accounting estimates include:
Decommissioning obligations
Decommissioning costs will be incurred by the Company many years into the future. Amounts recorded for decommissioning obligations require the use of management’s best estimates of future decommissioning expenditures, expected timing of expenditures and future inflation rates. The estimates are based on internal and third-party information and calculations are subject to changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions, and changes in clean up technology. Actual costs and outflows can differ from estimates and may have a material impact on earnings or financial position. For more information on the Company’s decommissioning obligations, see Note 10 of the Company’s audited annual financial statements for the year ended December 31, 2014.
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| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 18 |
Business combination
Business combinations are accounted for using the acquisition method. Under this method, management makes estimates of the fair value of assets acquired and liabilities assumed which includes assessing the value of petroleum and natural gas properties based upon the estimation of recoverable quantities of Proved and Probable reserves being acquired.
Share-based payments
The Company measures the cost of its share-based payments to directors, officers, employees and consultants by reference to the fair value of the equity instruments using the Black-Scholes option pricing model at the date they are granted. The assumptions used in determining fair value include: expected life of the options, risk-free rates of return and stock price volatility. Changes to assumptions may have a material impact on the amounts presented. For more information on the Company’s share-based payments see Note 13(b) of the Company’s audited annual financial statements for the year ended December 31, 2014.
Income taxes
Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly, affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.
New and Amended Adopted Accounting Standards
Effective January 1, 2014, the Company adopted the following accounting policies:
| | (i) | Amendment to IAS 36Impairment of Assets, requires additional disclosure on the recoverable amounts of an impaired CGU. The adoption of this amendment had no impact on the amounts recorded in the financial statements for the year ended December 31, 2014 or on the comparative periods. |
| | | |
| | (ii) | IFRIC 21Levies, clarifies the requirements for recognizing a liability for a levy imposed by a government. The adoption of this standard had no impact on the amounts recorded in the financial statements for the year ended December 31, 2014 or on the comparative periods. |
| | | |
| | (iii) | The Company changed its accounting for depleting its petroleum and natural gas properties. The Company changed from using the unit-of-production method based on production volumes in relation to total estimated Proved reserves to total estimated Proved and Probable reserves. The change in policy has been applied retrospectively. |
Disclosure Controls and Procedures
Disclosure controls and procedures ("DC&P"), as defined in National Instrument 52-109Certification of Disclosure in Issuers’ Annual and Interim Filings("NI 52-109"), are designed to provide reasonable assurance that 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 is recorded, processed, summarized and reported within the time periods specified under securities legislation and include controls and procedures designed to ensure that information required to be so disclosed is accumulated and communicated to management, including the Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO"), as appropriate, to allow timely decisions regarding required disclosure.
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| 19 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
The CEO and the CFO have evaluated the effectiveness of the Company’s disclosure controls and procedures as at December 31, 2014 and have concluded that such disclosure controls and procedures are effective. 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").
Internal Controls over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control 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 generally accepted accounting principles. Internal control over financial reporting includes 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 generally accepted accounting principles, 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.
Because of its inherent limitations, internal control over financial reporting 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 assessed the Company’s internal control over financial reporting as of December 31, 2014. Management based its assessment on criteria established in COSO 2013. Management’s assessment included evaluation of such elements as the design and operating effectiveness of key financial reporting controls, process documentation, accounting policies, and the Company’s overall control environment.
Based on Management’s assessment, it has been concluded that the internal controls over financial reporting was effective, as at December 31, 2014, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with IFRS as issued by the IASB.
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 December 31, 2014, the Company's financial instruments include accounts receivable, reclamation deposits, bank indebtedness, accounts payable and accrued liabilities.
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| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 20 |
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.
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.
| Hemisphere Energy Corporation |
| 21 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
The maximum exposure to credit risk is as follows:
| | | December 31, 2014 | | | December 31, 2013 | |
Accounts receivable | | | | | | |
Trade receivables | $ | 1,041,843 | | $ | 927,768 | |
Receivables from joint venture | | 95,355 | | | 42,663 | |
Reclamation deposits | | 105,535 | | | 105,535 | |
Total | $ | 1,242,733 | | $ | 1,075,966 | |
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 December 31, 2014, the Company had a negative working capital of $11,644,609 (December 31, 2013 - $6,330,906), which includes bank indebtedness of $7,184,147 (December 31, 2013 - $4,500,000). 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 loss and comprehensive 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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| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 22 |
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 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 Measurements
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 December 31 | | | Year Ended December 31 | |
| | | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
| | Cash provided by operating activities | $ | 1,546,991 | | $ | 849,925 | | $ | 6,659,680 | | $ | 3,665,274 | |
| | Change in non-cash working capital | | 212,568 | | | 270,102 | | | (13,353 | ) | | (123,928 | ) |
| | Funds flow from operations | $ | 1,334,422 | | $ | 579,824 | | $ | 6,673,033 | | $ | 3,789,202 | |
| | Funds flow from operations per share, basic and diluted | $ | 0.02 | | $ | 0.01 | | $ | 0.10 | | $ | 0.07 | |
| | 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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| 23 | | MANAGEMENT’SDISCUSSIONANDANALYSIS |
| | 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:
| | | | December 31, 2014 | | | December 31, 2013 | |
| | Current assets | $ | 1,437,181 | | $ | 1,145,579 | |
| | Current liabilities(1) | | (5,897,643 | ) | | (2,976,486 | ) |
| | Bank indebtedness | | (7,184,147 | ) | | (4,500,000 | ) |
| | Net debt | $ | (11,644,609 | ) | $ | (6,330,906 | ) |
| | Note: |
| | (1) | Excluding bank indebtedness and flow-through premium liability. |
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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| MANAGEMENT’S DISCUSSION AND ANALYSIS | | 24 |
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 newinformation, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.
| Hemisphere Energy Corporation |
