Vancouver, British Columbia – 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⁾

Note:
(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⁾

Notes:

(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.

2019 Finding and Development Costs and Recycle Ratios⁽¹⁾⁽²⁾

Notes:
(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)

Pricing Assumptions

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.

Reserve Life Index (“RLI”)

Notes:
(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⁾

Notes:

(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.

Corporate Outlook

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.

Balance Sheet

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.

Hedge Book

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:

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”.