Vancouver, British Columbia–(Newsfile Corp. – March 26, 2020) – Hemisphere Energy Corporation (TSXV: HME) (“Hemisphere” or the “Company”) is pleased to announce highlights from its independent reserves evaluation effective as at December 31, 2019 prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”). Following the discussion on reserves, Hemisphere has included an update to its corporate outlook and 2020 capital plans.
During 2019 Hemisphere incurred capital expenditures of approximately $11 million, which included capital to drill 11 producing wells in the Upper Mannville G pool. This activity resulted in a Proved Developed Producing (“PDP”) reserve valuation of $115.7 million (net present value of future net revenue, discounted at 10%, before tax (“NPV10 BT”)), representing a 69% increase when compared to year-end 2018. Production growth of 50% was also attained year over year to an average of approximately 1,665 boe/d (97% heavy crude oil and 3% conventional natural gas).
As a result of changes in guidance in the Canadian Oil and Gas Handbook (“COGEH”), the value associated with the 2019 year-end reserves now includes 100% of Hemisphere’s corporate abandonment, decommissioning, and reclamation estimates (“ADR”), including all the ADR associated with both active and inactive wells regardless of whether such wells had any attributed reserves. Despite this change, Hemisphere experienced significant reserve and valuation growth year over year in all categories, as compared below.
2019 Reserve Highlights
Proved (“1P“) Reserves
- Increased NPV10 BT by 39% to $198.2 million.
- Increased reserve volumes by 30% to 9.9 Mboe (98% heavy crude oil and 2% conventional natural gas).
- Replaced 478% of estimated 2019 production through organic development.
- Achieved a two-year average Finding & Development Cost (“F&D cost”) of $5.80/boe (including changes in Future Development Capital (“FDC”)) for a recycle ratio of 4.3.
- Increased NPV10 BT per basic share by 41% to $2.23.
- Improved Net Asset Value (“NAV”) by 54% to $1.56 per fully diluted share, including valuation of undeveloped land and seismic, corporate ADR, and proceeds of options and warrants.
- Reserve Life Index (“RLI”) of 16.3 years based on estimated 2019 production.
Proved plus Probable (“2P“) Reserves
- Increased NPV10 BT by 18% to $234.5 million.
- Increased reserve volumes by 15% to 12.2 MMboe (98% heavy crude oil and 2% conventional natural gas).
- Replaced 360% of estimated 2019 production through organic development.
- Achieved a two-year average F&D cost of $5.02/boe (including changes in FDC) for a recycle ratio of 4.9.
- Increased NPV10 BT per basic share by 20% to $2.64.
- Improved NAV by 25% to $1.89 per fully diluted share, including valuation of undeveloped land and seismic, corporate ADR, and proceeds of options and warrants.
- RLI of 20.1 years based on estimated 2019 production.
The reserves data set forth below is based upon an independent reserves evaluation prepared by McDaniel dated March 25, 2020 with an effective date of December 31, 2019, and is in accordance with definitions, standards, and procedures contained within COGEH and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in Hemisphere’s Annual Information Form which will be filed on SEDAR on or before April 30, 2020. Due to rounding, certain totals in the columns may not add in the following tables. All dollar values are in Canadian dollars, unless otherwise noted.
Summary of Reserves(1)
|Total Proved plus Probable||11,948.4||1,483.8||12,195.7|
(1) Reserves are presented as “gross reserves” which are the Company’s working interest reserves before royalty deductions and without including any royalty interests.
Summary of Net Present Value of Future Net Revenue(1)(2)
|Net Present Value of Future Net Revenue, Before Tax
(M$, except per share amount)
|Discounted at (% per Year)|
|Total Proved plus Probable||407,008.0||303,009.5||234,513.2|
|Per basic share(3)|
|Proved plus Probable||$4.58||$3.41||$2.64|
(1) Based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. at January 1, 2020, as outlined in the table herein entitled “Pricing Assumptions”.
(2) The net present value of future net revenue does not represent the fair market value of Hemisphere’s reserves.
(3) Based on there being 88,902,302 issued and outstanding shares of the Company as of December 31, 2019.
Future Development Costs (“FDC”)
The following summarizes the development costs deducted in the estimation of the net present value of the future net revenue attributable to 1P and 2P reserves.
|Proved plus Probable
|Total Discounted at 10%||30,422||31,146|
2019 Finding and Development Costs and Recycle Ratios(1)(2)
|2019||2019 and 2018
|Exploration and development capital (M$)(4)(5)||10,443||10,443||25,991||25,991|
|Total change in FDC (M$)||-4,742||-12,067||8,822||4,328|
|Total F&D capital, including change in FDC (M$)||5,701||-1,624||34,813||30,319|
|Reserve additions, including revisions (Mboe)||2,907||2,187||6,002||6,034|
|F&D costs, including FDC ($/boe)||1.96||nmf(7)||5.80||5.02|
(1) All financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2019 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, 2019 and the review and approval of same with the Company’s audit committee and board of directors.
(2) See “Oil and Gas Advisories” and “Oil and Gas Metrics”.
(3) F&D costs are calculated as the sum of development capital plus the change in future development capital 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 and estimated 2019 production of 1,665 boe/d.
(4) The aggregate of the exploration and development costs incurred in the financial year and change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
(5) The capital expenditures also exclude capitalized administration costs.
(6) Recycle ratio is calculated as operating netback divided by F&D costs. Operating netback is calculated as the operating field netback plus the Company’s realized commodity hedging gain (loss) per barrel of oil equivalent. Operating field netback is calculated as the Company’s oil and gas sales, less royalties, operating expenses and transportation costs per barrel of oil equivalent. The Company‘s estimated operating netback in 2019 was $30.80/boe (unaudited) and the combined two-year average for 2019 and 2018 was $24.81/boe (unaudited).
(7) FDC reductions exceeded capital spending in 2019, resulting in a ‘not meaningful figure’ (nmf)
McDaniel’s independent evaluation was based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. (the “Consultant Average Price Forecast”) at January 1, 2020, with the following table detailing pricing and foreign exchange rate assumptions. Overall, the Consultant Average Price Forecast of WTI and WCS pricing is down an average of approximately 6% and 3%, respectively, from McDaniel’s January 1, 2019 outlook over the same 15 year period.
Light Crude Oil
|Western Canadian Select
|Thereafter||Escalation Rate of 2%/year||2.0||0.785|
Reserve Life Index (“RLI”)
|As at December 31|
|Proved Developed Producing||8.1||8.1|
|Proved plus Probable||20.1||26.2|
(1) Calculated as the applicable reserves volume divided by Hemisphere’s average 2019 production of 1,665 boe/d.
(2) Calculated as the applicable reserves volume divided by Hemisphere’s average 2018 production of 1,111 boe/d.
Net Asset Value (“NAV”)(1)
|As at December 31|
|(M$ except share amounts)||Proved||Proved plus
|Undeveloped Land & Seismic||1,112(3)||1,723(4)|
|Proceeds from Warrants and Stock Options||5,571||5,571|
|ADR not included in Reserve Report (NPV10 BT)(2)||–||(900)|
|Shares Outstanding (basic)||88,902,302||89,793,302|
|Shares Outstanding (fully diluted)||110,836,302||111,962,302|
|NAV per share (basic)||$1.88||$2.29||$1.21||$1.83|
|NAV per share (fully diluted)||$1.56||$1.89||$1.01||$1.51|
(1) Based on the January 1, 2020 Consultant Average Price Forecast.
(2) 2019 valuation includes 100% of corporate ADR whereas 2018 valuation only includes corporate ADR for wells with assigned reserves. Total corporate ADR accounted for in the 2018 reserve report amounts to $1.3 and $1.4 million NPV10 BT in the Proved plus Probable and Proved categories, respectively. Total corporate ADR accounted for in the 2019 reserve report amounts to $2.3 million NPV10 BT in each of the Proved plus Probable and Proved categories.
(3) Based on an internal evaluation by management of Hemisphere as of December 31, 2019 with an average value of $50 per acre for 11,197 undeveloped net acres, and $0.55 MM for seismic.
(4) Based on an internal evaluation by management of Hemisphere as of December 31, 2018 with an average value of $50 per acre for 23,424 undeveloped net acres, and $0.55 MM for seismic.
(5) All financial information as at December 31, 2019 is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2019 which has 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, 2019 and the review and approval of same with the Company’s audit committee and board of directors.
Additions to the Company’s independently prepared reserve evaluation were achieved in 2019 due to the recognition of significant development activity and successful waterflood response in the Atlee Buffalo area. Of the 71 MMbbl Original Oil in Place (“OOIP”) mapped by McDaniel across both of the Upper Mannville F and G pools, overall aggregate recovery factors of 17.5% (1P) to 20% (2P) are reflected in McDaniel’s reserve report as at December 31, 2019. Last year, as at December 31, 2018, overall aggregate recovery factors of 13% (1P) to 17% (2P) were reflected in McDaniel’s reserve report of the same assets. Increases to recovery factor recognition are due to an increased level of time on production and overall confidence in the performance of these pools under waterflood.
- 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 16% and 25%, respectively, of Alberta Energy mapped oil in place. After approximately 20 years of waterflood, these pools produced in January 2020 at approximately 66% and 45% of peak pool oil rates, respectively, and have maintained relatively flat production over the past five years. Management expects these analogue pools to reach recovery factors much higher than those already attained, and in turn anticipates continued increases to McDaniel’s booked recovery factors for Hemisphere’s Atlee Buffalo Upper Mannville F and G pools with further development.
- Reserves have been booked in the Atlee Buffalo F pool at a total pool recovery factor of approximately 15% (1P) to 18% (2P) of McDaniel’s mapped 31 MMbbl OOIP. There are currently 13 producing wells in the pool.
- Reserves have been booked in the Atlee Buffalo G pool at a total pool recovery factor of approximately 19% (1P) to 22% (2P) of McDaniel’s mapped 40 MMbbl OOIP. There are currently 19 producing wells in the pool, including 11 producers drilled in 2019.
- 30 Proved Atlee Buffalo drilling locations have been attributed reserves in McDaniel’s reserve report as at December 31, 2019.
Hemisphere’s Liability Management Rating (“LMR”) with the Alberta Energy Regulator (“AER”) is 11.15 as of March 7, 2020, which is within the top 8% of all companies evaluated by the AER. Total corporate ADR on all existing properties is estimated by management at $8.1 million unescalated ($1.8 million NPV10 BT, with costs escalated at 2%/yr), with 100% of the ADR accounted for in the PDP category of the reserve report. Hemisphere has always believed that carefully managing liabilities is a critical component of being a successful Canadian oil and gas company, and management fully supports the changes to the COGEH guidelines on ADR this year.
Hemisphere grew significantly in production and reserve value in 2019 within its low decline, long life oil assets. Corporate production over the first quarter is tracking approximately 1975 boe/d to date, based on field estimates from Jan 1-Mar 22, 2020 (99% heavy crude oil and 1% conventional natural gas). This growth has positioned Hemisphere as a stronger company with the agility to navigate these unprecedented times. With Hemisphere’s low operating expenses and robust hedge book, the Company is prepared to weather the current price environment. Hemisphere had minimal capital expenditures during the first quarter of 2020 and plans to defer all non-essential capital spending until oil prices increase. The Company will evaluate the economics of individual wells and shut-in decisions will be made on a well by well basis if required. In response to COVID-19, Hemisphere will continue to focus on the safety of staff and service providers by following the Alberta and British Columbia health guidelines.
Hemisphere has currently drawn US$25.5 million on its US$35 million multidraw, non-revolving, five-year term loan facility with an expiry date of September 2022. Hemisphere has a supportive relationship with its lender Cibolo Energy Partners. Cibolo is a Houston, Texas firm exclusively focused on upstream energy companies.
Hemisphere’s risk management program will help mitigate near-term oil price volatility. The Company’s hedge book has a mark-to-market gain of approximately US$5.7 million (Cdn$8.3 million) as of market close on March 23, 2020.
Hemisphere currently has the following crude oil hedge contracts:
|Crude oil||Swap||425 bbl/d||US$58.40||WTI-NYMEX||January 1, 2020 – March 31, 2020|
|Crude oil||Swap||425 bbl/d||US$55.85||WTI-NYMEX||April 1, 2020 – June 30, 2020|
|Crude oil||Swap||100 bbl/d||US$16.95||WCS||April 1, 2020 – June 30, 2020|
|Crude oil||Swap||100 bbl/d||US$15.25||WCS||April 1, 2020 – June 30, 2020|
|Crude oil||Swap||100 bbl/d||US$14.35||WCS||April 1, 2020 – June 30, 2020|
|Crude oil||Swap||200 bbl/d||US$50.67||WTI-NYMEX||January 1, 2020 – August 31, 2020|
|Crude oil||Swap||425 bbl/d||US$55.85||WTI-NYMEX||July 1, 2020 – September 30, 2020|
|Crude oil||Swap||100 bbl/d||US$15.30||WCS||July 1, 2020 – September 30, 2020|
|Crude oil||Collar||120 bbl/d||US$40.00-US$68.25||WTI-NYMEX||January 1, 2020 – December 31, 2020|
|Crude oil||Collar||200 bbl/d||US$40.00-US$67.05||WTI-NYMEX||September 1, 2020 – December 31, 2020|
|Crude oil||Swap||425 bbl/d||US$54.85||WTI-NYMEX||October 1, 2020 – December 30, 2020|
|Crude oil||Collar||275 bbl/d||US$40.00-US$65.50||WTI-NYMEX||January 1, 2021 – March 31, 2021|
|Crude oil||Collar||350 bbl/d||US$40.00(put)/US$48.60(put)/US$60(call)||WTI-NYMEX||January 1, 2021 – March 31, 2021|
|Crude oil||3-Way Collar||625 bbl/d||US$40.00(put)/US$48.00(put)/US$60(call)||WTI-NYMEX||April 1, 2021 – June 30, 2021|
Through these challenging times, the Company will remain diligent and responsive to the changing markets as the year progresses, including looking extensively for opportunities that arise from this environment. Hemisphere would like to thank its devoted and hard-working staff and contractors and its many dedicated shareholders for their continued support.
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 focusing on existing assets with significant growth potential and executing strategic acquisitions. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol “HME”.
For further information, please visit the Company’s website at www.hemisphereenergy.ca to view its corporate presentation or contact:
Don Simmons, President & Chief Executive Officer
Telephone: (604) 685-9255
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 of Hemisphere’s oil and gas reserves and the estimated net present values of the future net revenues of such reserves; Hemisphere’s estimated 2019 average corporate production rate; the anticipation by Hemisphere for the recovery factors for the N2N and YYY pools reaching recovery factors that are higher than currently estimated; the anticipation for continued increases to McDaniel’s booked recovery factors for the Upper Mannville F and G pools with further development; Hemisphere’s belief that having a strong LMR is a critical component of being a successful Canadian oil and gas company; Hemisphere’s statements under “Corporate Outlook” herein, including as it relates to its ability to deal with current commodity prices, the deferral of all non-essential capital spending, and the potential to shut-in production; and the Company’s anticipated filing date for its annual information form for the year ending December 31, 2019.
The estimates of Hemisphere’s reserves and the recovery factors 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 impact of COVID-19 on the Company’s operations and demand for oil and natural gas; 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 to, or restrictions of, labour, supplies, and infrastructure as a result of COVID-19; 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.
It should not be assumed that the net present value of the estimated net revenues presented in this news release represent 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 in this news release on a before tax basis.
“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 news 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, 2019. 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.
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, 2019 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.
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 calculated as the operating netback divided by the F&D cost per boe for the year.
“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 news release, should not be relied upon for investment or other purposes.
This news release discloses drilling locations in one category proved locations. Proved locations are derived from the Company’s most recent independent reserves evaluation as prepared by McDaniel and effective as of December 31, 2019 and account for drilling locations that have associated proved or probable reserves, as applicable. 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.
All financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2019 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, 2019 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.
The news release contains terms commonly used in the oil and gas industry which are not defined by or calculated in accordance with International Financial Reporting Standards (“IFRS”), such as: (i) net debt; and (ii) operating netback, operating netback per boe and operating field netback. These terms should not be considered an alternative to, or more meaningful than the comparable IFRS measures (as determined in accordance with IFRS) which in the case of operating field netback and operating netback, are cash flow from operating activities and net income or net loss, respectively. There is no IFRS measure that is reasonably comparable to net debt. These measures are commonly used in the oil and gas industry and by Hemisphere to provide shareholders and potential investors with additional information regarding: (i) in the case of operating netback, operating netback per boe and operating field netback, the indication of the Company’s profitability relative to current commodity prices; and (ii) in the case of net debt, the capital structure and financial position of the Company.
Hemisphere’s determination of these measures may not be comparable to that reported by other companies. Net debt is calculated as the total of the Company’s bank debt and current liabilities, less current assets. Operating netback is calculated as the operating field netback plus the Company’s realized commodity hedging gain (loss) per barrel of oil equivalent. Operating netback per boe is calculated as operating netback divided by the applicable barrels of oil equivalent of production. Operating field netback is calculated as the Company’s oil and gas sales, less royalties, operating expenses and transportation costs. The Company has provided additional information on how these measures are calculated in the Management’s Discussion and Analysis for the year ended December 31, 2018 and for the three and nine month period ended September 30, 2019, which are available under the Company’s SEDAR profile at www.sedar.com.
Definitions and Abbreviations
|bbl||barrel||$US||United States dollar|
|Mbbl||thousands of barrels||$Cdn||Canadian dollar|
|MMbbl||millions of barrels||M$||thousand dollars|
|boe||barrel of oil equivalent||MM||million|
|boe/d||barrel of oil equivalent per day||NPV10 BT||Net Present Value of future net revenue, discounted at 10%, before tax|
|Mboe||thousands of barrels of oil equivalent||WTI||West Texas Intermediate|
|MMboe||millions of barrels of oil equivalent||WCS||Western Canadian Select|
|MMcf||million cubic feet||AECO||Alberta Energy Company|
|MMbtu||million British Thermal Unit||FDC||Future Development Costs|
|F&D||Finding and Development Costs|
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
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