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Research News and Market Data on HMENF

March 12, 2024 8:30 AM EDT

Vancouver, British Columbia–(Newsfile Corp. – March 12, 2024) – Hemisphere Energy Corporation (TSXV: HME) (OTCQX: HMENF) (“Hemisphere” or the “Company”) is pleased to announce highlights from its independent reserves evaluation (the “Reserve Report”), prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) and effective as at December 31, 2023.

In 2023, Hemisphere invested $16 million to drill eight successful Atlee Buffalo wells, upgrade facilities in Atlee Buffalo, purchase land and seismic, and pre-purchase some of the materials for its 2024 development program. With the Company’s capital additions, corporate production in 2023 increased by more than 10% year-over-year, to 3,124 boe/d (99% heavy oil). Production is currently trending over 3,450 boe/d (99% heavy oil, based on field estimates between February 10 – March 10, 2024), after significant downtime experienced in January and early February due to extreme cold weather and equipment failure.

During the year, Hemisphere also distributed $13.1 million in base and special dividends, purchased 3.2 million shares under its normal course issuer bid (“NCIB”) for a total price of $4.0 million (at an average price of $1.25/share), and exited the year in a cash position with working capital¹ of over $3 million.

The Company’s continued success in the development of its enhanced oil recovery projects was recognized again by McDaniel in the Reserve Report. In the Proved Developed Producing (“PDP”) category, Hemisphere replaced 104% of 2023 production and increased reserve value by 9% to $248 million NPV10 BT. Hemisphere also grew Proved (“1P”) reserve value to $325 million NPV10 BT and Proved plus Probable (“2P”) reserve value to $416 million NPV10 BT.

The Company’s new Saskatchewan lands currently account for only 5% of 1P and 7% of 2P reserves, while making up only 3% of 1P and 5% of 2P NPV10 BT valuations of Hemisphere’s reserves. Significant reserve upside remains on Hemisphere lands if the play proves successful over the course of 2024 and beyond.

Consistent with McDaniel’s 2022 year-end evaluation, the Reserve Report incorporates full corporate abandonment, decommissioning, and reclamation costs (“ADR”) in the PDP category. Hemisphere has always been cautious of acquiring additional wellbore and facility liabilities. A direct result of this strategy is that Hemisphere’s reserves retain more comparative value per barrel than companies with additional ADR liabilities that must be deducted from their base valuations. Management estimates that total undiscounted and uninflated existing ADR is $8.3 million ($2.3 million NPV10 BT, with costs inflated at 2%/yr), which includes all ADR associated with both active and inactive wells, pipelines, and facilities regardless of whether such wells, pipelines, and facilities had any attributed reserves. Based on public information, Hemisphere stands out among its industry peers as being within the top 8% of Alberta oil and gas operators for its industry-leading liability management ratio (“LMR”) of 17, resulting in Hemisphere having less than 1% of its PDP net present value impaired by ADR.

Hemisphere’s low decline, long life, and high value reserves are a sign of the tremendous resource the Company has been developing over the past number of years. These valuable assets are the backbone of Hemisphere and are expected to generate significant free cash flow as they continue to grow with planned additional development and optimization of enhanced oil recovery techniques.

2023 Reserve Highlights

Proved Developed Producing (“PDP”) Reserves

• NPV10 BT of $248 million, an increase of 9% over year-end 2022 and equivalent to $2.49 per basic share.
• Replaced 104% of 2023 production through organic development.
• Maintained reserve volumes year-over-year at 8.2 MMboe (99.6% heavy crude oil).
• Achieved a 2-year FD&A cost of $9.30/boe (including changes in future development capital (“FDC”)) for a recycle ratio of 5.4.
• RLI of 7.2 years based on 2023 production.

Proved (“1P”) Reserves

• NPV10 BT of $325 million, an increase of 5% over year-end 2022 and equivalent to $3.27 per basic share.
• Replaced 90% of 2023 production through organic development.
• Maintained reserve volumes year-over-year at 12.1 MMboe (99.4% heavy crude oil).
• Achieved a 2-year FD&A cost of $14.82/boe (including changes in FDC) for a recycle ratio of 3.4.
• RLI of 10.6 years based on 2023 production.
• NAV of $3.18 per fully diluted share based on Reserve Report pricing assumptions.
• NAV of $3.28 and $4.27 per fully diluted share based on Reserve Report run internally at McDaniel’s pricing sensitivities of US$80 and US$100 WTI flat pricing.

Proved plus Probable (“2P”) Reserves

• NPV10 BT of $416 million, an increase of 5% over year-end 2022 and equivalent to $4.19 per basic share.
• Replaced 125% of 2023 production through organic development.
• Maintained reserve volumes at 16.3 MMboe (99.4% heavy crude oil).
• Achieved a 2-year FD&A cost of $14.91/boe (including changes in FDC) for a recycle ratio of 3.4.
• RLI of 14.3 years based on 2023 production.
• NAV of $4.03 per fully diluted share based on Reserve Report pricing assumptions.
• NAV of $4.12 and $5.36 per fully diluted share based on Reserve Report run internally at McDaniel’s pricing sensitivities of US$80 and US$100 WTI flat pricing.

2023 Independent Qualified Reserve Evaluation

The reserves data set forth below is based upon an independent reserves evaluation prepared by McDaniel dated March 11, 2024 with an effective date of December 31, 2023, 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, 2024. 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.

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 “3-Consultant Average Price Forecast”) at January 1, 2024, with the following table detailing pricing and foreign exchange rate assumptions. Hemisphere’s corporate production historically averages a discount of approximately $4.50 to WCS pricing. When compared to last year’s 3-Consultant Average Price Forecast dated January 1, 2023, the current WCS pricing outlook is down approximately 1% in 2024, and up 1% thereafter over the next 15-year period. The 2024 3-Consultant Average Price Forecast uses a 5-year 2024-28 WTI price of US$76.33/bbl and WCS price of Cdn$81.11/bbl.

3-Consultant Average Price Forecast January 1, 2023									3-Consultant Average Price Forecast January 1, 2024
	WTI Crude Oil ($US/bbl)	Edmonton Light Crude Oil ($Cdn/bbl)	Western Canadian Select WCS Crude Oil ($Cdn/bbl)	AECO Spot Price ($Cdn/MM Btu)	Inflation (%)	US/Cdn Exchange Rate ($US/$Cdn)			WTI Crude Oil ($US/bbl)	Western Canadian Select WCS Crude Oil ($Cdn/bbl)	Edmonton Light Crude Oil ($Cdn/bbl)	AECO Spot Price ($Cdn/MM Btu)	Inflation (%)	US/Cdn Exchange Rate ($US/$Cdn)
2024	78.50	97.74	77.75	4.40	2.3	0.765		2024	73.67	92.91	76.74	2.20	0	0.745
2025	76.95	95.27	77.55	4.21	2	0.768		2025	74.98	95.04	79.77	3.37	2	0.765
2026	77.61	95.58	80.07	4.27	2	0.772		2026	76.14	96.07	81.12	4.05	2	0.768
2027	79.16	97.07	81.89	4.34	2	0.775		2027	77.66	97.99	82.88	4.13	2	0.772
2028	80.74	99.01	84.02	4.43	2	0.775		2028	79.22	99.95	85.04	4.21	2	0.775
2029	82.36	100.99	85.73	4.51	2	0.775		2029	80.80	101.94	86.74	4.30	2	0.775
2030	84.00	103.01	87.44	4.60	2	0.775		2030	82.42	103.98	88.47	4.38	2	0.775
2031	85.69	105.07	89.20	4.69	2	0.775		2031	84.06	106.06	90.24	4.47	2	0.775
2032	87.40	106.69	91.11	4.79	2	0.775		2032	85.74	108.18	92.04	4.56	2	0.775
2033	89.15	108.83	92.93	4.88	2	0.775		2033	87.46	110.35	93.89	4.65	2	0.775
2034	90.93	111.00	94.79	4.98	2	0.775		2034	89.21	112.56	95.77	4.74	2	0.775
2035	92.75	113.22	96.69	5.08	2	0.775		2035	90.99	114.81	97.68	4.84	2	0.775
2036	94.61	115.49	98.62	5.18	2	0.775		2036	92.81	117.10	99.64	4.94	2	0.775
2037	96.50	117.80	100.59	5.29	2	0.775		2037	94.67	119.45	101.63	5.03	2	0.775
2038	98.43	120.16	102.60	5.40	2.00	0.78		2038	96.56	121.83	103.66	5.14	2.00	0.78

Summary of Reserves⁽¹⁾

	Heavy Oil	Conventional Natural Gas	Total
Reserves Category	(Mbbl)	(MMcf)	(Mboe)
Proved
Developed Producing	8,196	173	8,225
Developed Non-Producing	34	7	35
Undeveloped	3,756	250	3,798
Total Proved	11,987	429	12,058
Probable	4,231	188	4,262
Total Proved plus Probable	16,217	617	16,320

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, Before Tax (“NPV BT”) ⁽¹⁾⁽²⁾

	NPV BT (M$, except per share amount)
	Discounted at (% per Year)
Reserves Category	0%	5%	10%
Proved
Developed Producing	363,872	295,324	247,832
Developed Non-Producing	720	603	513
Undeveloped	126,954	97,757	76,777
Total Proved	491,546	393,685	325,121
Probable	190,663	126,483	91,337
Total Proved plus Probable	682,209	520,168	416,458
Per basic share(3)
Proved Developed Producing	3.66	2.97	2.49
Proved	4.95	3.96	3.27
Proved plus Probable	6.87	5.24	4.19

Notes:
(1) Based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. at January 1, 2024, as outlined in the table herein entitled “Pricing Assumptions”.
(2) It should not be assumed that the estimates of net present value of future net revenues presented in this table represent the fair market value of Hemisphere’s reserves.
(3) Based on there being 99,340,339 issued and outstanding shares of the Company as of December 31, 2023.

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.

	Forecast Costs (M$)
	1P	2P
2024	16,410	16,410
2025	22,959	28,051
2026	7,087	12,648
2027	3,501	3,501
Subsequent years	–	–
Total Undiscounted	49,956	60,609
Total Discounted at 10%	43,568	52,209

Finding, Development and Acquisition Costs (“FD&A”) Costs and Recycle Ratios⁽¹⁾⁽²⁾

	2023			2-Year Totals/Average
FD&A	PDP	1P	2P	PDP	1P	2P
Exploration, development and acquisition capital (M$)(3)(4)	14,543			31,570
Total changes in FDC (M$)	-528	4,869	10,094	-2,527	2,191	9,888
Total FD&A Capital, including changes in FDC (M$)	14,015	19,412	24,637	29,044	33,762	41,458
FD&A Reserve additions, including revisions (Mboe)	1,181	1,027	1,425	3,123	2,278	2,780
FD&A costs(5), including changes in FDC ($/boe)	11.87	18.90	17.28	9.30	14.82	14.91
Recycle Ratio(6)	3.8	2.4	2.6	5.4	3.4	3.4

Notes:
(1) All financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, 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, 2023, 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) Exploration, development and acquisition capital excludes capitalized administration costs.
(4) The aggregate of the exploration, development and acquisition capital incurred in the financial year and change during that year in estimated future development costs generally will not reflect total finding, development and acquisition costs related to reserve additions for that year.
(5) FD&A costs are calculated as the sum of exploration, development and acquisition capital plus the change in future development capital (FDC) for the period divided by the change in reserves for the period, including on acquisition lands. FD&A costs take into account reserves revisions during the year on a per boe basis, and 2023 production of 3,124 boe/d.
(6) Recycle ratio is calculated as Operating field netback divided by FD&A costs. Operating field netback is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the sections “Non-IFRS and Other Specified Financial Measures” and “Financial Information”. The Company‘s estimated operating field netback in 2023 was $45.41/boe (unaudited) and 2-year 2022/23 average operating field netback was $50.67/boe.

Reserve Life Index (“RLI”)

	As of December 31, 2023(1)
PDP	7.2
1P	10.6
2P	14.3

Note:
(1) Calculated as the applicable reserves volume divided by Hemisphere’s average 2023 production of 3,124 boe/d.

Net Asset Value (“NAV”)⁽¹⁾

	As at December 31, 2023
(MM$ except share amounts)	3-Consultant Average Price Forecast	US$80 WTI	US$100 WTI
1P NPV10 BT(2)	325	336	441
2P NPV10 BT(2)	416	426	558
Undeveloped Land and Seismic(3)	3
Proceeds from Stock Options	9
Working Capital(4)	3
Million Shares Outstanding (fully diluted)	107
1P NAV per share (fully diluted)	$3.18	$3.28	$4.27
2P NAV per share (fully diluted)	$4.03	$4.12	$5.36

Notes:
(1) Calculated using the respective net present values of 1P and 2P reserves, before tax and discounted at 10%, plus internally valued undeveloped land & seismic and proceeds from and stock options, plus working capital⁽⁴⁾, and divided by fully diluted outstanding shares. Net present values are shown at various price forecasts including the 3-Consultant Average Price Forecast used in the McDaniel Reserve Report, as well as sensitivities run internally at McDaniel’s flat WTI price forecasts of US$80 and US$100 WTI paired with US$19.32 and US$23.45 WCS differentials, respectively, and 1.37 USD/CAD FX.
(2) 100% of existing and future corporate ADR has been included in the McDaniel Reserve Report. Total corporate ADR accounted for in the 2023 reserve report, including that for future development, amounts to $3.0 million NPV10 BT in the 1P category and $3.1 million NPV10 BT in the 2P category.
(3) Based on an internal evaluation by management of Hemisphere as of December 31, 2023, with an average value of $75.87 per acre for 31,295 undeveloped net acres, and $0.55 million for seismic.
(4) Working Capital is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the section “Non-IFRS and Other Specified Financial Measures”. All financial information as at December 31, 2023 is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, 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, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors.

About Hemisphere Energy Corporation

Hemisphere is a dividend-paying Canadian oil company focused on maximizing value per share growth with the sustainable development of its high netback, low decline conventional heavy oil assets through water and polymer flood enhanced recovery methods. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol “HME” and on the OTCQX Venture Marketplace under the symbol “HMENF”.

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
Email: info@hemisphereenergy.ca

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	NPV BT	Net Present Value of future net revenue, before tax
Mboe	thousands of barrels of oil equivalent	NPV10 BT	NPV BT, discounted at 10%
MMboe	millions of barrels of oil equivalent	FX	Foreign Exchange
MMcf	million cubic feet	FDC	Future Development Costs
MMbtu	million British Thermal Unit	FD&A	Finding, Development and Acquisition
AECO	Alberta Energy Company	NAV	Net Asset Value
WCS	Western Canadian Select	RLI	Reserve Life Index
WTI	West Texas Intermediate

Forward-Looking Statements

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 Company’s expectations that its assets are expected to generate significant free funds flow as they continue to grow with planned additional development and optimization of enhanced oil recovery techniques; the volumes of Hemisphere’s oil and gas reserves and the estimated net present values of the future net revenues of such reserves; the Company’s estimates of ADR; and the Company’s anticipated filing date for its annual information form for the year ending December 31, 2023; upside potential on Hemisphere’s Saskatchewan properties in 2024 and beyond. 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 can be profitably produced in the future.

The 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; inflation rates and cost escalations; 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; regulatory risks, including penalties or other remedial action; the ability of the Company to maintain legal title to its properties; 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; changes in budgets; 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. Estimates of net present value and future net revenue contained herein do not necessarily represent fair market value. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions in evaluating Hemisphere’s reserves will be attained and variances could be material.

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.

Oil and Gas Metrics

This news release contains metrics commonly used in the oil and natural gas industry, such as finding, development and acquisition (“FD&A”) costs, “recycle ratio”, “operating field 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, development and acquisition costs” or “FD&A costs” are calculated as the sum of exploration, development and acquisition capital plus the change in future development capital (“FDC”) for the period divided by the change in reserves for the period, including on acquisition lands. FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration, development and acquisition costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total FD&A costs related to reserves additions for that year. Management uses FD&A costs as a measure of capital efficiency for organic reserves development.

“Exploration, development and acquisition capital” means the aggregate exploration, development and acquisition costs incurred in the financial year, and excludes capitalized administration costs.

“Recycle ratio” is a Non-IFRS ratio calculated as the Operating field netback divided by the FD&A cost per boe for the year. Operating field netback is a non-IFRS financial measure (refer to the section “Non-IFRS and Other Specified Financial Measures”). Management uses recycle ratio to relate the cost of adding reserves to the expected cash flows to be generated.

“Reserve life index” is calculated as total company interest reserves divided by annual production, for the year indicated.

“NAV per fully diluted share” is calculated using the respective net present values of 1P and 2P reserves, before tax and discounted at 10%, plus internally valued undeveloped land & seismic and proceeds from warrants and stock options, plus working capital, and divided by fully diluted outstanding shares. Net present values are shown at various price forecasts including the 3-Consultant Average Price Forecasts used in the McDaniel Reserve Report, as well as sensitivities run internally at McDaniel’s flat WTI price forecasts of US$80 and US$100 WTI paired with US$19.32 and US$23.45 WCS differentials respectively, and 1.37 USD/CAD FX. Management uses NAV per share as a measure of the relative change of Hemisphere’s net asset value over its outstanding common shares over a period of time.

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.

Financial Information

Certain financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, 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, 2023, 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.

Non-IFRS and Other Specified Financial Measures

Certain measures commonly used in the oil and natural gas industry referred to herein, including “Working Capital” and “Operating field netback”, do not have standardized meanings prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other companies. These non-IFRS measures are further described and defined below. Investors are cautioned that these measures should not be construed as alternatives to or more meaningful than the most directly comparable IFRS measures as indicators of Hemisphere’s performance. Set forth below are descriptions of the non-IFRS financial measures used in this news release.

“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. Working Capital is used in this document in the context of liquidity and is calculated as the total of the Company’s bank debt plus current assets, less current liabilities, excluding the fair value of financial instruments, lease and decommissioning liabilities.

($MM)		Twelve Months Ended December 31, 2022 (unaudited)
Bank debt	$	–
Current assets		13.3
Current liabilities		(9.9	)
Working Capital	$	3.4

“Operating field netback” is calculated as oil and gas sales, less royalties, operating expenses, and transportation costs on an absolute and per barrel of oil equivalent basis. Operating netback per boe and Operating field netback per boe are calculated by dividing the respective terms by the applicable barrels of oil equivalent of production. A reconciliation of Operating netback and Operating field netback per boe to the most directly comparable measure calculated and presented in accordance with IFRS is as follows:

($/boe)		Twelve Months Ended December 31, 2022 (unaudited)
Average realized sales	$	74.05
Royalties		(14.89	)
Operating and transportation expenses		(13.75	)
Operating field netback	$	45.41

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, 2022 and for the three and nine month periods ended September 30, 2023, which are available under the Company’s SEDAR+ profile at www.sedarplus.ca.

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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1 Working Capital is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the sections “Non-IFRS and Other Specified Financial Measures” and “Financial Information”.

SOURCE: Hemisphere Energy Corporation