Calima Energy : Brooks and Thorsby Reserves Update 2022

For personal use only

28 March 2022

Brooks and Thorsby Reserves Update 2022

Highlights

•  Blackspur Reserves as at 31 December 2021 - audited by InSite Petroleum Consultants Ltd:

•	3P reserves	24.4 million boe
•	2P Reserves	20.4 million boe
•	1P Reserves	15.6 million boe
•	PDP Reserves	5.1 million boe

•  Blackspur drilled 12 wells in 2021 of which 11 were proven undeveloped locations (PUD) which moved locations from the 1P category to cash flow generating Proven Developed Producing (PDP) wells.

•  The focused asset bases of Brooks and Thorsby coupled with high graded infill drilling and prudent production management allowed Blackspur to maintain reserves steady after production of 1.1 million boe since 31 Dec 2020.

•  Updated Reserve Report and Development Plan incorporates:

  • o 60 development wells as 54 PUD's and 6 probable

  • o Development plan is designed for proved and probable well locations to be drilled within a 5-year period

  • o Costs for abandonment, decommissioning, reclamation, and salvage of facilities, and inactive assets for all of the Company's existing and proposed wells

  • o Preparation in accordance with the Society of Petroleum Engineers' Petroleum Resources Management System (SPE-PRMS)

•  Blackspur estimates approximately 228net wells will develop the entire reserve position on its existing lands > 5 years out.

  • o 90% of undeveloped Brooks and Thorsby acreage has no reserves booked currently, representing significant upside to the existing report

Calima Energy Limited (ASX:CE1 / OTCQB: RLTOF) (Calima or Company) is pleased to announce InSite Petroleum Consultants Ltd ("InSite") has completed its reserves evaluation as at 31 December 2021 for Calima's wholly owned subsidiary Blackspur Oil Corp. ("Blackspur").

Table 1: Reserve Statement

Calima Energy Ltd ACN 117 227 086

FOLLOW US

Suite 4, 246-250 Railway Parade, West Leederville WA 6007: [phone] Fax: + 61 8 6500 3275 Email:[e-mail]

For personal use only

Development Plan

The development plan in the 31 December 2021 Reserve Report consists of 60 (gross) wells to be drilled over 5 years. The schedule and breakdown in each reserve category is summarised in the table below.

Table 2: Rig and gross well count for each year

As at 31 December 2021, the 2022 development program includes 13 wells to be drilled including, 3 Thorsby Sparky wells, 4 Brooks Sunburst wells, and 6 Brooks Glauconite wells (2 are now drilled as part of the Pisces campaign).

Blackspur's working interest in each well dictates the reserves the Company can book during the well's productive life. On a net well count for the proved reserve category, Blackspur has a ~92% interest in the proved undeveloped wells in the 31 December 2021 development plan for 2022.

As at 31 December 2021, Blackspur held the rights to ~110,500 net acres within the Brooks and Thorsby areas. The Company operates 67.6 net wells developing approximately 8,700 net acres of this position.

The year-end reserve development schedule encompass development of a modest portion of the total acreage position that Blackspur holds. Based on the existing leasehold position, including the acreage associated with the existing producing wells, Blackspur estimates a total of approximately 228 (net) wells will develop the entire reserve position. The total 31 December 2021 development schedule corresponds to 60 future wells, or 24% of the wells necessary to develop the entire acreage position. Approximately 90% of the undeveloped Brooks and Thorsby acreage does not have reserves booked, representing significant upside.

InSite assessed all future locations they determined to be commercial. The key assumptions used by InSite to generate the Reserve Report were:

• • The majority of the reserve estimates were prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

• • The oil price used for all reserves analysis in this report is stated in the table at the end of this release. The reserves are disclosed net to the point of sale (reference point) and are reported net of lease fuel.

• • Blackspur is the operator for materially all its producing wells and all the future drills.

• • Operating costs for developed producing wells are based on actual costs incurred through YE2021. Operating costs for future wells and years are based on the same data and estimated following a review of operating statements, operating budgets, as well as review of public records where available. Cross checks were conducted between the revenue statements and land data to ensure they agreed. Fixed and variable costs have been assigned to Blackspur's active assets with remaining reserves. Operating costs associated with

Calima Energy Ltd ACN 117 227 086

FOLLOW US

Suite 4, 246-250 Railway Parade, West Leederville WA 6007: [phone] Fax: + 61 8 6500 3275 Email:[e-mail]

For personal use only

inactive assets as well as producing wells with no reserves assigned have been entered as separate entities at the property level.

• • In conducting InSite's reserve analysis, proved, probable and possible reserve volumes were determined by volumetric, material balance, and production decline curve methods. The volumetric reserves were determined by reviewing all well logs, core, and geological data. Recovery factors were assigned after analyzing the performance of similar wells in the area. Historical well production was reviewed to determine reserves calculated by production decline curve analysis. The order of preference in choosing the methodology to be used was primarily production decline curve analysis or material balance where sufficient data was available for such analysis with volumetrics being used where there was a lack of historical data.

• • 100% of the proved producing reserves were calculated based on decline analysis, oil-cut analysis and other performance/volumetric related prediction methods, compared to 33.1% (33% net) of the total proved reserves and 30.9% (30.9% net) of the proved plus probable reserves, and 31.0% (31% net) of proved plus probable plus possible reserves which used these methods. Volumetrics/simulation/analogy/type curve analyses were used to calculate the remaining percentages of reserves in each category.

• • The EUR assignments are largely influenced by the production performance of existing producing wells and their associated volumetric recovery. In the case of undeveloped drilling locations, reserve assignments and production profiles are based on analogy to the offsetting producers in the nearby vicinity and/or other analogous pools.

• • The probable reserves contained in the report consist of two general types:

  • o Performance-related (i.e. Proved plus Probable Developed) reserves represent the best estimate overall. Proved reserves are a more conservative estimate of the recovery from wells where Possible reserves represent a more optimistic and lower probability estimate.

  • o Proved plus probable reserves can also include enhanced recovery reserves which are only partially recognized under proved reserves. The "wedge" or difference between the Proved Developed and Proved plus Probable Developed cases represents 29.9% (29.5% net) of the Company's Probable reserves. The "wedge" between Proved plus Probable Developed and Proved plus Probable plus Possible Developed cases represents 33.6% (32.4% net) of the Company's Possible reserves.

• • Future horizontal step-out wells represent 65.9% (65.6% net) of the Company's probable reserves.

• • Future vertical step-out wells represent 4.7% (4.9% net) for the Company's probable reserves.

• • The oil and gas reserve calculations and income projections upon which this report is based were determined in accordance with generally accepted evaluation practices and evaluation process was consistent with prior years.

• • Proposed future well locations are allocated a reserve category based on proximity to existing wells and production.

• • Probable reserves were assigned such that there is a 50% probability that the assigned reserves could be recovered, or more on an aggregated basis.

• • Proved plus Probable plus Possible reserves were assigned such that there is a 10% probability that the assigned reserves could be recovered, or more on an aggregated basis.

• • The production and revenue forecasts contained in the 31 December 2021 evaluation include abandonment and reclamation costs for each of the Company's existing and proposed wells that were assigned reserves in

Calima Energy Ltd ACN 117 227 086

FOLLOW US

Suite 4, 246-250 Railway Parade, West Leederville WA 6007: [phone] Fax: + 61 8 6500 3275 Email:[e-mail]

For personal use only

this report. These costs were determined using the Alberta Energy Regulator's Directive 011 as a base. The costs associated with abandonment, decommissioning, reclamation, and salvage of facilities, as well as inactive assets, have been entered as separately.

• • The five-year development plan used for this reserve report is detailed in Table 2 above and assumes a multi rig program to develop a total of 60 gross well locations. The development plan assumes 2-6 wells per standard development unit and approximately 128 - 160 acre spacing.

• • Anticipated drilling, completion & tie-in well costs range from C$1.0 to C$3.4 million depending on whether it's a Sunburst, Glauconitic or Sparky well.

• • The development plan assumes an initial estimate of 6-14 days respectively to drill new wells.

• • Average royalties payable on future well locations that were allocated reserves in this report is ~15% over the life of the wells. The land type and related royalties are either Crown or Freehold and the average royalty for the PDP forecast for 2022 is 18.2%.

Each year, for the purposes of estimating undeveloped reserves, a development schedule is generated which must be appropriate and reasonable for the Company to execute on. This development plan is prepared in consultation with InSite and takes into consideration market conditions and the Company's operational capacity, including financing and historical drilling activity. The plan must also conform to the various ASX and SPE-PRMS requirements, the key points of which are:

• • the development plan is executed over a 5-year period from the effective date.

• • proved well locations must be drilled within 5 years of the date they were first certified as a reserve in previous reports.

• • The InSite evaluation has been prepared for the Company in accordance with reserves definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook and have been classified in accordance with the Society of Petroleum Engineers' Petroleum Resources Management System (SPE-PRMS) and reported in the most specific resource class in which the prospective resource can be classified under 2018 SPE-PRMS. The reserves presented in the InSite report are based on forecast prices and costs. The price forecast used for the reference price of oil based on Cushing, Edmonton and Western Canadian Select benchmarks, as well as the netback prices for natural gas for the major purchasers. All oil prices used in the evaluation have been adjusted from the reference price for quality and transportation; gas prices have been adjusted for heating value. Please note that the effects of any oil or gas hedging activities by the Company have not been included in this report. The reserves are disclosed net to the reference point.

• • In the context of belonging to a larger portfolio of properties and coupled with the principal of aggregation of reserves, the total portfolio reserves estimate carries a higher degree of confidence than the estimates for the individual properties.

Calima Energy Ltd ACN 117 227 086

FOLLOW US

Suite 4, 246-250 Railway Parade, West Leederville WA 6007: [phone] Fax: + 61 8 6500 3275 Email:[e-mail]

For personal use only

Blackspur Reserves (net of royalties)

30

25

20

MMBOE

15

10

5

0

2021-06-30

2021-12-31

1P2P3P

Graph 1: Reserve Summary

Brooks
31 December
Brooks asset overview	2021
Land position and production
Core land position (net acres)	>40,000
Core formation targets	Sunburst, Glauconitic
Average working interest of the play (%)	90%
Number of wells drilled to date (net)	>60
Identified drilling locations (Net)	130
February 2022 average production (boe/d)	~2,400
Reserves (mmboe)(1)
Proved reserves	8
Probable reserves	2
Total proved plus probable reserves	10
Possible reserves	1.7
Total proved plus probable plus possible	11.7

Calima has an established core position of land (~63 net sections or ~40,500 net acres) and significant infrastructure that creates a foundation for growth and expansion, and importantly with year-round access. The Brooks asset averaged net daily production of 2,400 boe/d in February 2022.

Blackspur + Calima have drilled >60 wells to date in this area and production comes from the Sunburst and Glauconitic Formations. Blackspur's existing Brooks infrastructure can process up to 8,200 bbl/d oil providing significant upside with limited infrastructure spend. The Brooks reservoirs have a low CO2 content at 2, and our multi-well pad drilling reduces environmental footprint. The Sunburst Formation can be developed at low well cost of ~ C$1 million, delivering attractive rates of return and most importantly, short paybacks of ~4-6 months at US$70 WTI and standard type curves.

Calima Energy Ltd ACN 117 227 086

FOLLOW US

Suite 4, 246-250 Railway Parade, West Leederville WA 6007: [phone] Fax: + 61 8 6500 3275 Email:[e-mail]