Vancouver, British Columbia, February 14, 2017 – Hemisphere Energy Corporation (TSX-V: HME) (“Hemisphere” or the “Company”) is pleased to announce highlights from its independent reserves evaluation as at December 31, 2016 prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”).
In 2016, Hemisphere’s estimated average corporate production rate was 526 boe/d (86% oil). Throughout the year the Company invested $2.4 million of development capital with specific focus on drilling its first producing oil well in the Atlee Buffalo G Pool and building a water handling and reinjection facility at its Atlee Buffalo F Pool. With very little capital spent in a year of depressed commodity pricing, Hemisphere achieved another year of significant reserve growth adding 823 Mboe of Proved plus Probable reserves at a finding and development cost (“F&D”) of $7.49/boe, including changes in future development costs (“FDC”). This year-over-year growth was primarily due to waterflood performance recognition in the Atlee Buffalo F & G Pools despite only having drilled one well this year.
2016 Reserve Highlights
- Increased Proved plus Probable reserves by 16% to 4,564.3 Mboe (96% oil) and net present value by 36% to $65.9 million (NPV10 BT).
- Added 823 Mboe of Proved plus Probable reserves, replacing 427% of estimated 2016 production at an F&D cost of $7.49/boe, including changes in FDC.
- Added 353 Mboe of Proved plus Probable Developed Producing reserves, increasing the net present value by 20% to $37.9 million (NPV10 BT) and replacing 183% of estimated 2016 production.
- Increased Proved reserves by 13% to 3,141.1 Mboe (96% oil) and net present value by 33% to $45.7 million (NPV10 BT).
- Added 549 Mboe of Proved reserves, replacing 285% of estimated 2016 production at an F&D cost of $8.96/boe, including changes in FDC.
- Added 268 Mboe of Proved Developed Producing reserves, increasing the net present value by 20% to $30.0 million (NPV10 BT) and replacing 139% of estimated 2016 production.
- Achieved a 2 year average F&D of $2.45/boe on a Proved plus Probable basis and $3.86/boe on a Proved basis, including changes in FDC, for recycle ratios of 6.7 and 4.2 respectively.
- Proved plus Probable reserves net present value (NPV10 BT) increased by 20% to $0.77/share on a per basic share basis.
- Hemisphere’s December 31, 2016 net asset value is internally calculated at $0.67/share on a per basic share basis.
- Proved plus Probable reserve life index is 23.7 years based on Hemisphere’s estimated 2016 average production.
Year-end 2016 Reserves
The reserves data set forth below is based upon an independent reserves evaluation prepared by McDaniel with an effective date of December 31, 2016 and is in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in Hemisphere’s Annual Information Form which will be filed on SEDAR on or before April 28, 2017. Due to rounding, certain totals in the columns may not add in the following tables.
Summary of Reserves(1)
|Heavy Oil||Natural Gas||Total|
|Total Proved Plus Probable||4,364.8||1,196.6||4,564.3|
- Reserves are presented as “gross reserves” which are the Company’s working interest reserves before royalty deductions.
Summary of Net Present Value of Future Net Revenue(1)(2)
|Net Present Value of Future Net Revenue, Before Tax
(M$, except per share amount)
|Discounted at (% per Year)|
|Total Proved Plus Probable||120,542.7||86,477.1||65,902.4|
|Per basic share(3)||$1.41||$1.01||$0.77|
- Based on McDaniel December 31, 2016 forecast prices.
- The net present value of future net revenue does not represent the fair market value of Hemisphere’s reserves.
- Based on there being 85,745,102 issued and outstanding shares as of December 31, 2016.
Future Development Costs (“FDC”)
The following summarizes the development costs deducted in the estimation of the net present value of the future net revenue attributable to Proved reserves and Proved plus Probable reserves (using forecast prices and costs only).
|Forecast Prices and Costs|
|Proved plus Probable Reserves (M$)|
Total Discounted at 10%
2016 Finding and Development Costs and Recycle Ratios(1)
|2016||2015 and 2016
|Proved Plus Probable||Proved Plus Probable|
|Exploration and development capital (M$)(2)(3)||2,378.2||2,378.2||5,150.6||5,150.6|
|Total change in FDC (M$)||2,534.4||3,785.6||293.4||-1,033.4|
|Total F&D capital, including change in FDC (M$)||4,912.6||6,163.8||5,444.0||4,117.2|
|Reserve additions, including revisions (Mboe)||548.5||822.9||1,408.7||1,680.7|
|F&D costs, including FDC ($/boe)||8.96||7.49||3.86||2.45|
- All financial information is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2016 which have not yet been approved by the Company’s audit committee or board of directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2016 and the review and approval of same with the Company’s audit committee and board of directors.
- The aggregate of the exploration and development (or exploration, development, and acquisition if applicable) costs incurred in the financial year and change during that year in estimated future development costs generally will not reflect total finding and development (or exploration, development, and acquisition if applicable) costs related to reserve additions for that year.
- The capital expenditures also exclude capitalized administration costs. See “Oil and Gas Advisories”.
- Recycle ratio is calculated as operating netback divided by F&D (or FD&A if applicable) costs. Operating netback is calculated as revenue minus royalties, operating expenses, and transportation The Company‘s estimated operating netback in 2016 was $12.62/boe (unaudited) and the combined two-year average for 2015 and 2016 was $16.32/boe (unaudited).
Summary of McDaniel Pricing as of January 1, 2017
The following table is McDaniel’s forecast pricing and foreign exchange rates as at January 1, 2017 which were used in the preparation of McDaniel’s reserve evaluation. Overall, McDaniel’s forecast of WTI and WCS pricing is down approximately 7% from the January 1, 2016 outlook over the same 15 year period.
Light Crude Oil
|Western Canadian Select
|Thereafter||Escalation Rate of 2%/year||2.0||0.850|
Reserve Life Index (“RLI”)
|As at December 31|
|Proved Developed Producing||8.9||5.8|
|Proved plus Probable||23.7||13.9|
- Based on Hemisphere’s estimated 2016 average production of 526 boe/d.
- Based on Hemisphere’s 2015 average production of 776 boe/d.
Net Asset Value (“NAV”)
Based on McDaniel January 1, 2017 forecast pricing, Hemisphere’s net asset value as of December 31, 2016 is estimated to be $0.67 per share, calculated as follows:
|(M$ except per share amounts)||2016|
|Proved plus Probable Reserves (NPV10 BT)||65,902|
|Undeveloped Land & Seismic(1)||2,850|
|Estimated Net Debt (unaudited)(2)||(11,600)|
|Shares Outstanding (basic)||85,745|
|Estimated Net Asset Value per share (basic)||$0.67|
- Based on an internal evaluation by management of Hemisphere as of December 31, 2016 with an average value of $50 per acre for 46,000 undeveloped net acres, and $0.55 MM for seismic.
- All financial information is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2016 which have not yet been approved by the Company’s audit committee or board of directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to changes as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2016 and the review and approval of same with the Company’s audit committee and board of directors.
Additions to Proved reserves were achieved this year due to recognition of waterflood response in both the Atlee Buffalo F and G Upper Mannville Pools, despite having drilled only one well in 2016.
- Reserves have been booked in the Atlee Buffalo F Pool at a total pool recovery factor of approximately 10% (Proved) to 12% (Proved plus Probable) of McDaniel’s mapped 28 MMbbl original oil in place. There are eight total producing wells in the pool, with none drilled in 2016.
- Reserves have been booked in the Atlee Buffalo G Pool at a total pool recovery factor of approximately 4% (Proved) to 5% (Proved plus Probable) of McDaniel’s mapped 38 MMbbl original oil in place. There is currently only one producing well in the pool, which was placed on production in mid-2016.
- Analogues to Hemisphere’s Atlee Buffalo pools include the nearby Upper Mannville N2N and YYY pools. These pools have been producing under waterflood since the late 1990’s and have already recovered 13% and 23%, respectively, of Alberta Energy mapped oil in place. Both pools are still producing and management expects that recovery factors will continue to increase with further production.
- Based on analysis of analogue performance in combination with internal reservoir simulation models, management anticipates that there is significant potential for Hemisphere to achieve greater ultimate recovery factors than those currently booked in both Atlee Buffalo pools.
- 10 Proved and 2 Probable Atlee Buffalo drilling locations have been attributed reserves as at December 31, 2016. Management believes that up to 42 additional locations exist (which are currently unbooked) across these pools in order to achieve recovery factors similar to those already seen at analogues.
In 2017, Hemisphere’s corporate strategy is to begin active development in Atlee Buffalo now that the concepts of horizontal drilling, liners to control sand production, and waterflood when applied to these pools have been demonstrated as a commercial method of development. The Company expects to see meaningful growth in production and reserves through the year with continued success during the development of its core properties.
About Hemisphere Energy Corporation
Hemisphere Energy Corporation is a producing oil and gas company focused on developing conventional oil assets with low risk drilling opportunities. Hemisphere plans continual growth in production, reserves and cash flow by drilling existing projects and executing strategic acquisitions. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol “HME”.
For further information, please contact:
Don Simmons, President & Chief Executive Officer
Telephone: (604) 685-9255
Scott Koyich, Investor Relations
Telephone: (403) 619-2200
This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the volumes and estimated value of Hemisphere’s oil and gas reserves; Hemisphere’s estimated 2016 average corporate production rate; the expectation that recovery factors will continue to increase with further production at the Upper Mannville N2N and YYY pools; the anticipation that there is significant potential for Hemisphere to achieve greater ultimate recovery factors than those currently booked in both Atlee Buffalo pools; the belief that up to 42 additional locations exist in Hemisphere’s Atlee Buffalo pools; Hemisphere’s expectation that it will see meaningful growth in production and reserves through the year with continued success during the development of its core properties; and the Company’s anticipated filing date for its annual information form for the year ending December 31, 2016.
The recovery and estimates of Hemisphere’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of Hemisphere which have been used to develop such statements and information but which may prove to be incorrect. Although Hemisphere believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Hemisphere can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: that Hemisphere will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities are consistent with past operations; the quality of the reservoirs in which Hemisphere operates and continued performance from existing wells; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Hemisphere’s reserve volumes; certain commodity price and other cost assumptions; continued availability of debt and equity financing and cash flow to fund Hemisphere’s current and future plans and expenditures; the impact of increasing competition; the general stability of the economic and political environment in which Hemisphere operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Hemisphere to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Hemisphere has an interest in to operate the field in a safe, efficient and effective manner; the ability of Hemisphere to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Hemisphere to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Hemisphere operates; and the ability of Hemisphere to successfully market its oil and natural gas products.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of Hemisphere’s products, the early stage of development of some of the evaluated areas and zones; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Hemisphere or by third party operators of Hemisphere’s properties, increased debt levels or debt service requirements; inaccurate estimation of Hemisphere’s oil and gas reserve volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Hemisphere’s public disclosure documents, (including, without limitation, those risks identified in this news release and in Hemisphere’s annual information form).
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and Hemisphere does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
Oil and Gas Advisories
All reserve references in this news release are “gross” or “Company interest reserves”. Such reserves are the Company’s total working interest reserves before the deduction of any royalties and without including any royalty interests of the Company. As of December 31, 2016, the Company did not have any royalty interests.
It should not be assumed that the net present value of the estimated net revenues presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of Hemisphere’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs and abandonment and reclamation costs and are stated prior to provision for interest and general and administrative expenses. Future net revenues have been presented on a before tax basis.
The information concerning Upper Mannville N2N and YYY analogue pools may be considered to be “analogous information” within the meaning of applicable securities laws. Such information was obtained by Hemisphere management throughout the year ended December 31, 2016 from various public sources including information available to Hemisphere through AccuMap. Management believes such information is analogous to the Atlee Buffalo Upper Mannville F and G pools in which Hemisphere has an interest and is relevant as it may help to demonstrate the reaction of such pools to waterflood stimulations. Hemisphere is unable to confirm whether the analogous information was prepared by a qualified reserves evaluator or auditor or in accordance with the COGE Handbook and therefore, the reader is cautioned that the data relied upon by Hemisphere may be in error and/or may not be analogous to the oil pools in which Hemisphere holds an interest.
“Boe” means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Original Oil In Place (“OOIP”) is used by Hemisphere in this press release as an equivalent to Discovered Petroleum Initially-In-Place (“DPIIP”). DPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook (COGEH), is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves and contingent resources; the remaining portion of DPIIP is unrecoverable. The OOIP/DPIIP set forth in this news release has been provided for the sole purpose of highlighting the recovery factors used by Hemisphere’s independent engineers in attributing reserves to Hemisphere effective as of December 31, 2016. It should not be assumed that any portion of the OOIP/DPIIP set forth in the news release is recoverable other than the portion which has been attributed reserves by Hemisphere’s independent engineers. There is uncertainty that it will be commercially viable to produce any portion of the OOIP/DPIIP other than the portion that is attributed reserves.
Oil and Gas Metrics
This news release contains metrics commonly used in the oil and natural gas industry, such as finding and development (“F&D”) costs”, “recycle ratio”, “operating netback”, ” and “reserve life index (“RLI”)”. These terms do not have a standardized meaning and the Company’s calculation of such metrics may not be comparable to the calculation method used or presented by other companies for the same or similar metrics, and therefore should not be used to make such comparisons.
“Finding and development costs” or “F&D costs” are calculated as the sum of development capital plus the change in future development capital (“FDC”) for the period divided by the change in reserves that are characterized as development for the period. Finding and development costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
“Development capital” means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital excludes capitalized administration costs.
“Recycle ratio” is measured by dividing the operating netback by F&D cost per boe for the year.
“Operating netback” is calculated using production revenues including realized hedging gains and losses on commodity contracts minus royalties, operating and transportation expenses calculated on a per boe basis.
“Reserve life index” is calculated as total company interest reserves divided by annual production, for the year indicated.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.
This press release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations, which are sometimes collectively referred to as “booked locations”, are derived from the Company’s most recent independent reserves evaluation as prepared by McDaniel and effective as of December 31, 2016 and account for drilling locations that have associated proved or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 54 drilling locations identified herein, 10 are proved locations, 2 are probable locations and 42 are unbooked locations. Unbooked locations have specifically been identified by management as an estimation of the Company’s drilling activities based on evaluation of applicable geologic, seismic, and engineering, production and reserves data on prospective acreage and geologic formations. The drilling locations on which the Company actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, certain of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
All financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2016 which have not yet been approved by the Company’s audit committee or board of directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2016 and the review and approval of same with the Company’s audit committee and board of directors. All amounts are expressed in Canadian dollars unless otherwise noted.
Net debt is a non-IFRS measure calculated as current assets minus current liabilities including bank indebtedness and excluding flow-through share premium. Operating netback is a non-IFRS measure calculated as the Company‘s oil and gas sales, less royalties, operating expenses and transportation costs per barrel of oil equivalent. Additional information relating to these non-IFRS measures, including the reconciliation between the applicable IFRS Measure and Non-IFRS Measure can be found in the Company’s most recent management’s discussion and analysis, which may be accessed through the SEDAR website (www.sedar.com).
Definitions and Abbreviations
|Mbbl||thousands of barrels||MM||million|
|MMbbl||millions of barrels||NPV10 BT||Net Present Value discounted at 10%, before tax|
|boe||barrel of oil equivalent||WTI||West Texas Intermediate|
|barrel of oil equivalent per day
thousands of barrels of oil equivalent
|Millions of parrels of oil equivalent
million cubic feet
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