Calgary, Alberta–(Newsfile Corp. – July 2, 2024) – Bengal Energy Ltd. TSX: BNG (“Bengal” or the “Company“) engaged GLJ Ltd. (“GLJ“) to provide an evaluation of the Company’s oil reserves and resources dated June 12, 2024, with an effective date of March 31, 2024 (the “GLJ Report“). The reserves and resources data set forth below is based upon the GLJ Report. GLJ is an independent reserves evaluator and the GLJ Report was prepared in accordance the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook“) and the reserve and resources definitions contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101“).

Reserves Summary

As announced by Bengal in its press release dated June 13, 2024, the Company’s proved plus probable (“2P“) reserves for the fiscal year ended March 31, 2024, were 1,857 thousand barrels of oil (“Mbbls“) compared to 5,477 Mbbls at March 31, 2023, and Bengal’s proved reserves (“1P“) were 872 Mbbls compared to 2,005 Mbbls at March 31, 2023.

The net present value (“NPV“) (NPV 10, before tax) of Bengal’s 2P reserves, net of future development costs, at March 31, 2024 was $42 million, or $0.09 per share, utilizing the forecast prices and cost assumptions of GLJ as at March 31, 2024, and the NPV (NPV 10, before tax) of Bengal’s 1P reserves, net of future development costs, at March 31, 2024 was $18.6 million, or $0.04 per share, utilizing the forecast prices and cost assumptions of GLJ as at March 31, 2024. These lower reserve volumes as at March 31, 2024, as compared to March 31, 2023, are primarily due to a significant reduction in the number of proved and probable undeveloped future drilling locations, and reserve volumes being reclassified as contingent resources as described below, and marginally offset by upward technical revisions associated with slower than expected natural declines.

All evaluations of future net production revenue set forth in the tables below are based on the forecast prices and cost assumptions of GLJ as at March 31, 2024, and are after direct lifting costs, normal allocated overhead, and future development costs. It should not be assumed that the estimates of future net revenues presented herein 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 the Company’s oil reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual oil reserves may be greater than or less than the estimates provided herein.

Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form for the 2023 fiscal year (the “AIF“), which will be filed on SEDAR+ today.

Summary of Oil and Gas Reserves as at March 31, 2024 (Forecast Prices and Costs)

LIGHT CRUDE OIL AND MEDIUM CRUDE OIL

HEAVY CRUDE OIL

CONVENTIONAL NATURAL GAS

NATURAL GAS LIQUIDS

TOTAL

RESERVES CATEGORY:

Gross (Mbbl)

Net (Mbbl)

Gross (Mbbl)

Net (Mbbl)

Gross (MMcf)

Net (MMcf)

Gross (Mbbl)

Net (Mbbl)

Gross (MBOE)

Net (MBOE)

PROVED

268

246

˗

˗

˗

˗

˗

˗

268

246

Developed Producing

247

227

˗

˗

˗

˗

˗

˗

247

227

Developed Non-Producing

21

19

˗

˗

˗

˗

˗

˗

21

19

Undeveloped

604

554

˗

˗

˗

˗

˗

˗

604

554

TOTAL PROVED

872

800

˗

˗

˗

˗

˗

˗

872

800

PROBABLE

985

901

˗

˗

˗

`

˗

˗

985

901

TOTAL PROVED PLUS PROBABLE

1,857

1,701

˗

˗

˗

˗

˗

˗

1,857

1,701

 

Notes:
(1) Estimates of reserves of natural gas include associated and non-associated gas.
(2) “Gross Reserves” are the Company’s working interest reserves (operating and non-operating) before the deduction of royalties and without including any royalty interest of the Company.
(3) “Net Reserves” are the Company’s working interest reserves (operating and non-operating) after deductions of royalty obligations plus the Company’s royalty interests.
(4) The numbers in this table may not add exactly due to rounding.
(5) BOE amounts have been calculated using a conversion rate of six mcf to one bbl. For additional information, see “Cautionary Statements – Barrels of Oil Equivalent” in this press release.

Net Present Values of Future Net Revenue as at March 31, 2024 (Forecast Prices and Costs)

																																		Unit Value Before Income Taxes
				BEFORE INCOME TAXES DISCOUNTED AT (%/year)															AFTER INCOME TAXES DISCOUNTED AT (%/year)															Discounted at 10%/year			Discounted at 10%/year
	($M)			0%			5%			10%			15%			20%			0%			5%			10%			15%			20%			($/BOE)			($Mcfe)
	PROVED
	Developed Producing			7,090			6,948			6,625			6,256			5,895			7,090			6,948			6,625			6,256			5,895			29.23			4.87
	Developed Non-Producing			934			762			630			528			447			934			762			630			528			447			32.95			5.49
	Undeveloped			20,410			15,130			11,353			8,662			6,721			20,410			15,130			11,353			8,662			6,721			20.50			3.42
	TOTAL PROVED			28,434			22,840			18,609			15,447			13,064			28,434			22,840			18,609			15,447			13,064			23.27			3.88
	PROBABLE			48,390			32,973			23,449			17,397			13,394			37,961			26,911			19,769			15,082			11,893			26.03			4.34
	TOTAL PROVED PLUS PROBABLE			76,824			55,813			42,058			32,844			26,458			66,395			49,750			38,378			30,529			24,957			24.73			4.12

 

Notes:
(1) Net present value of future net revenue includes all resource income: sale of oil, gas by-product reserves; processing of third-party reserves; and other income.
(2) Income taxes includes all resource income, appropriate income tax calculations and prior tax pools.
(3) The unit values are based on working interest reserve volumes before income tax.
(4) The numbers in this table may not add exactly due to rounding.
(5) See BOE amounts have been calculated using a conversion rate of six mcf to one bbl. For additional information, see “Cautionary Statements – Barrels of Oil Equivalent” in this press release.

Forecast Costs and Price Assumptions

GLJ employed the following pricing, exchange rate, and inflation rate assumptions in estimating the Company’s reserves using forecast prices and costs as at March 31, 2024. GLJ has only assigned light crude oil reserves in the GLJ Report with pricing based on Brent plus a 1% premium.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
FORECAST PRICES AND COSTS (AUSTRALIAN PROPERTIES AS OF MARCH 31, 2024)

		YEAR FORECAST			Inflation(2) Rate (%)			Brent ($Cdn/Bbl)			Exchange Rate(3) ($Cdn /$ US)			Brent(4) ($US/Bbl)
		2024 Q2-Q4(1)			0			111.18			0.745			82.83
		2025			2.0			107.95			0.755			81.50
		2026			2.0			106.54			0.765			81.50
		2027			2.0			107.95			0.765			82.58
		2028			2.0			110.05			0.765			84.19
		2029			2.0			112.29			0.765			85.90
		2030			2.0			114.56			0.765			87.64
		2031			2.0			116.82			0.765			89.37
		2032			2.0			119.16			0.765			91.16
		2033			2.0			121.54			0.765			92.98
		2034+			2.0			+2%/yr			0.765			+2%/yr

 

Notes:
(1) 2024 forecast pricing is for the last nine months (April 1 – December 31) of 2024.
(2) Inflation rates for forecasting prices and costs.
(3) Exchange rates used to generate the benchmark reference prices in this table.
(4) Crude oil pricing has been estimated by GLJ as Brent blend in US dollars. Historical futures contract price is an average of the daily settlement price of the near-month contract over the calendar month.

Weighted average historical prices realized by the Company for the year ended March 31, 2024, were USD$82.93 (CDN $112.29) Bbl for light crude oil and medium crude oil. All of the Company’s oil sales in Australia are based upon Brent oil pricing in US dollars plus a 1% oil quality premium.

The following table sets forth the actual pricing and exchange rate used in the GLJ Report:

	YEAR FORECAST			Brent x 1.01 ($Cdn/Bbl)			Exchange Rate(3) ($Cdn/$ US )			Brent(4) ($US/Bbl)
	2024 Q2-Q4(1)			112.34			0.745			82.83
	2025			109.03			0.755			81.50
	2026			107.60			0.765			81.50
	2027			109.03			0.765			82.58
	2028			111.15			0.765			84.19
	2029			113.41			0.765			85.90
	2030			115.71			0.765			87.64
	2031			117.99			0.765			89.37
	2032			120.35			0.765			91.16
	2033			122.76			0.765			92.98
	2034+			125.21			0.765			+2%/yr

 

Reconciliation of Company Gross Reserves by Product Type (Forecast Prices and Costs ⁽³⁾

				Light Crude Oil and Medium Crude Oil									Total BOE
	FACTORS			Gross Proved (Mbbl)			Gross Probable (Mbbl)			Gross Proved plus Probable (Mbbl)			Gross Proved (MBOE)			Gross Probable (MBOE)			Gross Proved Plus Probable (MBOE)
	March 31, 2023			2,005			3,472			5,477			2,005			3,472			5,477
	Extensions(1)			˗			˗			˗			˗			˗			˗
	Improved Recovery(1)			˗			˗			˗			˗			˗			˗
	Infill Drilling(1)			˗			˗			˗			˗			˗			˗
	Technical Revisions(2)(4)(5)			(1,071)			(2,487)			(3,558)			(1,071)			(2,487)			(3,558)
	Discoveries			˗			˗			˗			˗			˗			˗
	Acquisitions			˗			˗			˗			˗			˗			˗
	Dispositions			˗			˗			˗			˗			˗			˗
	Economic Factors			˗			˗			˗			˗			˗			˗
	Production			(62)			˗			(62)			(62)						(62)
	March 31, 2024			872			985			1,857			872			985			1,857

 

Notes:
(1) The above change categories correspond to standard set out in the COGE Handbook. For reporting under NI 51-101, reserves additions under Infill Drilling, Improved Recovery and Extensions would be combined and reported as Extensions and Improved recovery.
(2) Includes technical revisions due to reservoir performance, geological and engineering changes and reclassification of proved and probable undeveloped reserves as contingent resources.
(3) No heavy crude oil, natural gas liquids or conventional natural gas reserves were assigned as at March 31, 2022 or March 31, 2023 so there are no reconciliations to provide in respect of any such reserves.
(4) Includes economic revisions due to changes in economic limits; and working interest changes resulting from the timing of interest reversions and related to price and royalty factor changes.
(5) The negative technical revisions result from reclassification of volumes of proved and probable undeveloped reserves to contingent resources, in compliance with regulatory requirements defining the timing of development required to continue to carry these volumes as reserves.

Resources Summary
The contingent resources evaluated by GLJ and contained in the GLJ Report are in respect of the Cuisinier property, which is located within the Barta Block (Authority to Prospect 752) of the Cooper Basin, Australia within Production Licenses 303 and 1028. Bengal holds a 30.4% working interest (“WI“) in the Cuisinier property and it is operated by a third-party operator. Resources included herein are stated on a Company gross basis, unless noted otherwise. Company gross resources refers to Bengal’s 30.4% WI in the resources.

The following discussion is subject to a number of cautionary statements, assumptions, contingencies and risks as set forth in this press release. In addition to the discussion below, see “Cautionary Statements – Contingent Resources“. Unless otherwise indicated in this press release, all references to contingent resource volumes are contingent light crude oil and medium crude oil resources.

										Resources – Unrisked(1)															Resources – Risked(1)
							WI(6)			Low Estimate			Best Estimate			High Estimate			Chance of Discovery			Chance of Development			Low Estimate			Best Estimate			High Estimate
	Structure			Classification			(%)			Mbbl			Mbbl			Mbbl			%(4)			%(4)			Mbbl			Mbbl			Mbbl
	Cuisinier			Contingent (Development Unclarified)(5)			30.4			1,085			3,495			7,525			100.0			61.2			664			2,139			4,605
	Total Contingent Resources(2)(3)									1,085			3,495			7,525			100.0			61.2			664			2,139			4,605

 

Notes:
(1) See “Cautionary Statements – Contingent Resources” definitions for “contingent resources”, “Low Estimate”, “High Estimate”, “Best Estimate”, “risked” and “unrisked”.
(2) There is no certainty that it will be commercially viable to produce any portion of the resources.
(3) The risked resources have been risked for chance of discovery and for the chance of development. The chance of development is defined as the probability of a project being commercially viable. Quantifying the chance of development requires consideration of both economic contingencies and other contingencies, such as legal, regulatory, market access, political, social license, internal and external approvals and commitment to project finance and development timing. As many of these factors are extremely difficult to quantify, the chance of development is uncertain and must be used with caution. See “Cautionary Statements – Contingent Resources“.
(4) As all contingent resources are considered to be discovered, the chance of commerciality for contingent resources is equal to the chance of development. “Chance of development” is the estimated probability that, once discovered, a known accumulation will be commercially developed.
(5) The contingent resources have been sub-classified as development unclarified. The following items have been considered in the sub-classification process: (i) the Cuisinier field is part of the Barta Block (Authority to Prospect 752) and is currently on production with transportation infrastructure and marketing agreements in place; (ii) the future development includes drilling development wells with fracture stimulation. Additional capital is considered for the expansion of the trucking facility and for construction of a twin pipeline between Cook and Merrimelia to provide adequate capacity and develop completely; (iii) the development timeframe is limited by the timing of future drilling and facility capacity; however, the development timing remains within a range that is acceptable for reserves; (iv) the corporate commitment for development of contingent resources has been assessed as high; (v) as non-operator, Bengal may not have access to the operator’s internal approval process, but there is a high degree of certainty that development will occur; and (vi) the recovery technology is established as it will be primary depletion.
(6) Company gross resources refers to Bengal’s 30.4% WI in the resources.

The specific contingencies that need to be addressed before the resources can be re-classified as reserves are the following:

• Firm development plan and development timeframe – Actions and business decisions to further refine the project’s scope and timing to progress these development projects through final approvals to implementation and initiation of production.
• All new wells exhibiting hydrocarbons are required to be capable of commerciality.
• The definition of commerciality for an accumulation will vary according to local conditions and circumstances and is left to the discretion of the country or company concerned.
• There is an expectation that the accumulation will be developed and placed on production within a reasonable timeframe.

Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economics.

Background to the GLJ Report

During the calendar year 2023, the Company initiated an internal comprehensive review of its Cuisinier asset with a view to better understanding the field’s resource potential to complement its knowledge of its field reserve volumes defined annually by the reserves evaluation prepared for the Company by GLJ. The field’s subsurface mapping, reservoir simulation modelling and well performance were considerations for estimating the remaining resource potential of the asset. The studies for the GLJ Report included a detailed review of the seismic data base and subsequent remapping of the discovered and prospective hydrocarbon areas.

Future Plans

The Company has a development program planned for the Cuisinier field for a portion of the proved undeveloped reserves in 2025 through the drilling of four proved undeveloped wells in 2025, followed by similar programs in 2027 and 2029. Probable undeveloped reserves’ location drilling plans entail the drilling of one well in each of 2025, 2027 and 2029, with five wells planned to be drilled in 2031, focusing on the development drilling opportunities in the Cuisinier field in Australia, and subject to financing for such drilling being available to the Company.

About Bengal

Bengal Energy Ltd. is an international junior oil and gas exploration and production company with assets in Australia. The Company is committed to growing shareholder value through international exploration, production and acquisitions. Bengal’s common shares trade on the TSX under the symbol “BNG”. Additional information is available at www.bengalenergy.ca.

CAUTIONARY STATEMENTS:

Forward-Looking Statements

This press release contains certain forward-looking statements or information (“forward-looking statements“) as defined by applicable securities laws that involve substantial known and unknown risks and uncertainties, many of which are beyond Bengal’s control. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. The use of any of the words “plan”, “expect”, “future”, “project”, “prospective”, “intend”, “believe”, “should”, “anticipate”, “estimate”, “new”, “develop” or other similar words or statements or conditions that certain events “may” or “will” occur are intended to identify forward-looking statements. The projections, estimates and beliefs contained in such forward-looking statements are based on management’s estimates, opinions, and assumptions at the time the statements were made. Although the Company’s management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Bengal’s actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Bengal. As such, undue reliance should not be placed on forward-looking statements. The projections, estimates and beliefs contained in such forward-looking statements are based on management’s estimates, opinions, and assumptions at the time the statements were made, including assumptions relating to: the accuracy of the GLJ Report; the ability of the Company to implement its development plans; the impact of economic conditions in North America, Australia and globally; industry conditions; changes in laws and regulations including, without limitation, the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; increased competition; the availability of qualified operating or management personnel; fluctuations in commodity prices, foreign exchange or interest rates; stock market volatility and fluctuation; results of exploration and testing activities, and the continued or anticipated performance of assets; and the ability to obtain required approvals and extensions from regulatory authorities.

In particular, forward-looking statements contained herein include, but are not limited to, statements regarding: “resources” and “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources described exist in the quantities predicted or estimated, and that the resources described can be profitably produced in the future. Additional forward-looking statements in this press release include, but are not limited to, statements regarding: the Company’s focus, plans, priorities and strategies; the Company’s position in the business environment, particularly in the Australian business environment; future development of resources, including, without limitation, expectations regarding chance of commerciality, development and discovery; reserves and future net revenue from the Company’s reserves; future drilling plans; assumptions regarding oil sales, pricing and inflation rates; the anticipated timing of filing of the AIF; the specific contingencies that required to be addressed before the resources can be re-classified as reserves; the Company’s future plans; and risks and significant positive and negative factors with respect to the contingent resources identified in the GLJ Report.

The forward-looking statements contained herein are subject to numerous known and unknown risks and uncertainties that may cause Bengal’s actual financial results, performance or achievement in future periods to differ materially from those expressed in, or implied by, these forward-looking statements, including but not limited to, risks associated with: drilling wells, including the costs of drilling and whether development drilling results in commercially productive quantities of oil; Bengal’s dependency on third-party operators; estimations of reserves and the present value of future net revenues derived from them; the exploration and production of oil and natural gas, including but not limited to drilling and other operational and environmental risks and hazards; the failure to obtain required regulatory approvals or extensions; the failure to satisfy the conditions under farm-in and joint venture agreements; the failure to secure required equipment and personnel; changes in general global economic conditions including, without limitations, the economic conditions in North America and Australia; that the Company will not be commercially viable to produce any portion of the contingent resources disclosed herein; the ability to access sufficient capital from internal and external sources; political instability and the impacts of the Russian-Ukrainian conflict, the Israel-Hamas conflict and related actions; increased competition; the availability of qualified operating or management personnel; fluctuations in commodity prices, foreign exchange or interest rates; changes in laws and regulations including, without limitation, the adoption of new environmental and tax laws and regulations and changes in how they are interpreted and enforced; the results of exploration and development drilling and related activities; the ability to access sufficient capital from internal and external sources; and stock market volatility. Any historical production information should not be construed as an estimate of future production levels or future resources/reserves of Bengal. Readers are encouraged to review the material risks discussed in the AIF under the heading “Risk Factors” and in Bengal’s annual MD&A under the heading “Risk Factors“. The Company cautions that the foregoing list of assumptions, risks and uncertainties is not exhaustive. Additional information on these and other factors that could affect the Company are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR+ at www.sedarplus.ca. The forward-looking statements contained in this press release speak only as of the date hereof and Bengal does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be require pursuant to applicable securities laws.

Oil and Gas Advisory

The reserves information contained in this press release has been prepared in accordance with NI 51-101. Complete NI 51-101 reserves disclosure will be included in the AIF which will be filed on SEDAR+ today. Listed below are cautionary statements applicable to Bengal’s reserves information that are specifically required by NI 51-101:

• Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.
• This press release contains estimates of the net present value of our future net revenue from our reserves. Such amounts do not represent the fair market value of our reserves.
• Reserves included herein are stated on a company interest basis (before royalty burdens and including royalty interests) unless noted otherwise as well as on a gross and net basis as defined in NI 51-101. “Company interest” is not a term defined by NI 51-101 and as such the estimates of the Company interest reserves herein may not be comparable to estimates of “gross” reserves prepared in accordance with NI 51-101 or to other issuers’ estimates of company interest reserves.

Reserve Definitions

“Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and nonproducing.

“Developed producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

“Developed non-producing reserves” are those reserves that either have not been on production, or have previously been on production but are shut in and the date of resumption of production is unknown.

“Undeveloped reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable and possible) to which they are assigned.

“Proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

“Probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Light crude oil is crude oil with a relative density greater than 31.1 degrees API gravity, medium crude oil is crude oil with a relative density greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity, and heavy crude oil is crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity.

Barrels of Oil Equivalent

When converting natural gas to equivalent barrels of oil, Bengal uses the widely recognized standard of 6 mcf to one BOE. However, a BOE 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. 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.

Contingent Resources

The contingent resources shown have been estimated by GLJ as at March 31, 2024. Resource estimates carry a risk of development. The estimates have been determined using statistic volumetric methods based on the interpretation of porosity, hydrocarbon saturation and net reservoir thickness from the logging program, the analysis of potential hydrocarbon columns from the pressure data and the fluid properties derived from the gas and oil samples and applied to the structure map with recovery factors calculated using analogues and industry standards.

The existence of potentially moveable hydrocarbons and the determination of the presence of movable hydrocarbons was via petrophysical analysis and gas and oil produced to surface.

These are classified as contingent resources according to the COGE Handbook and NI 51-101 standards as the development concept has not yet been finalized or sanctioned.

Chance of Commerciality

The contingent resources have been risked for the chance of commerciality. The chance of commerciality is defined as follows:

• Chance of Commerciality = Chance of Development × Chance of Discovery
• Chance of Development: the estimated probability that, once discovered, a known accumulation will be commercially developed. Chance of Development = Corporate Commitment Factor × Development Plan Factor × Economic Factor × Development Timeframe Factor × Technology Factor.
• Chance of Discovery: the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum.

For contingent resources the chance of discovery is equal to one as the accumulation has been discovered and is defined as a known accumulation.

The following factors were considered in determining the chance of development:

• Corporate Commitment Factor – For reserves to be assessed, a project must have corporate sanctioning to proceed. With respect to contingent resources, this factor captures the uncertainty in the project evaluation scenario. The Corporate Commitment Factor will be one for reserves and high, approaching one, for development pending projects.
• Development Plan Factor – For reserves to be assessed, a project must have a detailed development plan. With respect to contingent resources, this factor captures the uncertainty in the project evaluation scenario. The Development Plan Factor will be one for reserves and high, approaching one, for development pending projects.
• Economic Factor – For reserves to be assessed, a project must be economic. With respect to contingent resources, this factor captures uncertainty in the assessment of economic status principally due to uncertainty in cost estimates and marketing options. The Economic Factor will be one for reserves and will often be one for development pending and for projects with a development study or pre-development study with a robust rate of return where market access is not a concern. A robust rate of return means that the project retains economic status with variation in costs and/or marketing plans over the expected range of outcomes for these variables.

• Development Timeframe Factor – In the case of major projects, for reserves to be assigned, first major capital spending must be initiated within five years of the effective date. The Development Timeframe Factor will be one for reserves and will often be one for development pending provided the project is planned on-stream based on the same criteria used in the assessment of reserves. With respect to contingent resources, the factor will approach one for projects planned on-stream with a timeframe slightly longer than the limiting reserves criteria.
• Technology Factor – For reserves to be assessed, a project must utilize established technology. With respect to contingent resources, this factor captures the uncertainty in the viability of the proposed technology for the subject reservoir, namely, the uncertainty associated with technology under development. By definition, technology under development is a recovery process or process improvement that has been determined to be technically viable via field test and is being field tested further to determine its economic viability in the subject reservoir. The Technology Factor will be one for reserves and for established technology. For technology under development, this factor will consider different risks associated with technologies being developed at the scale of the well versus the scale of a project and technologies which are being modified or extended for the subject reservoir versus new emerging technologies which have not previously been applied in any commercial application. The risk assessment will also consider the quality and sufficiency of the test data available, the ability to reliably scale such data and the ability to extrapolate results in time.

These factors may be interrelated (dependent) and care has been taken to ensure that risks are appropriately accounted.

Risks and Significant Positive and Negative Factors

The development of the contingent resources identified in the GLJ Report is dependent upon the following factors:

Factors regarding Development of Resources

Key positive factors relevant to the development of the property include:

• consistent growth in the local economy resulting in a steady increase in demand for crude oil natural gas in the region; and
• positive commodity price outlook for sales of natural gas and crude oil.

Key negative factors relevant to the development of the property include:

• potential for loss of access to processing and transportation systems which are owned by third parties;
• the emergence of new or alternative gas or energy supplies and the consequential impact on demand from the property; and
• adverse weather conditions and surface access difficulties.
• potential for insufficient access to capital to support required development activities.
• potential for misalignment between Bengal and the field operator that may impact future development activities.

Factors regarding Resource Estimates

Significant positive factors relevant to the estimates of the Company’s crude oil resources include:

• the Company’s knowledge of the property based on significant production history;
• the Company’s knowledge of drilling and completion techniques used to develop the property; and
• the Company’s strong track record of developing similar projects according to its plans.

Significant negative factors relevant to the estimate of the Company’s crude oil natural gas resources include:

• uncertainty in assumptions about forecasted demand; and
• uncertainty in assumptions about natural gas and oil pricing.

Resource Definitions

“contingent resources” are those quantities of petroleum estimated, as of the given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.

Contingent resources may be divided into the following project maturity sub-classes:

• “development pending” is assigned to contingent resources for a particular project where resolution of final conditions for development is being actively pursued (high chance of development).
• “development on hold” is assigned to contingent resources for a particular project where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator.
• “development unclarified” is assigned to contingent resources for a particular project where evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties.
• “development not viable” is assigned to contingent resources for a particular project where no further data acquisition or evaluation is currently planned and there is a low chance of development.

Contingent resources are defined probabilistically as:

• 1C: Low Estimate of Contingent Resources
• 2C: Best Estimate of Contingent Resources
• 3C: High of Contingent Resources

“economic” means those contingent resources that are currently economically recoverable.

“resources” encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced.

“risked” means the applicable reported volumes or revenues have been risked (or adjusted) based on the chance of commerciality of such resources in accordance with the COGE Handbook. In accordance with the COGE Handbook for contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies required for the re-classification of the contingent resources as reserves being resolved. Therefore, risked reported volumes and values of contingent resources reflect the risking (or adjustment) of such volumes or values based on the chance of development of such resources.

“unrisked” means applicable reported volumes or values of resources have not been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook for contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies required for the re-classification of the contingent resources as reserves being resolved. Therefore, unrisked reported volumes and values of contingent resources do not reflect the risking (or adjustment) of such volumes or values based on the chance of development of such resources.

“Uncertainty Ranges” are described by the COGE Handbook as low, best, and high estimates for resources. The range of uncertainty of estimated recoverable volumes may be represented by either deterministic scenarios or a probability distribution. Resources are provided as low, best and high estimates, as follows:

• Low Estimate – This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the Low Estimate. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the low estimate.
• Best Estimate – This is considered to be the Best Estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the Best Estimate. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the Best Estimate.
• High Estimate – This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the High Estimate. If probabilistic methods are used, there should be at least a 10 percent probability that the quantities actually recovered will equal or exceed the High Estimate.

Selected Definitions

The following terms used in this press release have the meanings set forth below:

• “bbl” means barrel
• “BOE” means barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for six mcf (this conversion factor is and industry accepted norm and is not based on either energy content or current prices)
• “Mbbl” means thousand barrels
• “MBOE” means 1,000 barrels of oil equivalent
• “mcf” means one thousand cubic feet
• “Mcfe” thousand feet of gas equivalent
• “MMcf’” means one million cubic feet

FOR FURTHER INFORMATION PLEASE CONTACT:

Bengal Energy Ltd.
Chayan Chakrabarty, President & Chief Executive Officer
Jerrad Blanchard, Chief Financial Officer
(403) 205-2526
Email: investor.relations@bengalenergy.ca
Website: www.bengalenergy.ca

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/215291