Prospera Energy Inc. (PEI) December 31, 2022 year-end reserves were independently assessed by InSite Petroleum Consultants Ltd. (“InSite”). The Insite report confirmed current recovery to date of 8.6% using mostly vertical wells, mainly in core assets (>42,000 acres) located in Southwest and West-Central Saskatchewan, with significant remaining recoverable reserves representing a substantial upside for PEI. Further, there were no modern drilling or recovery methods applied to these fields.
Therefore, the restructured PEI recommended transition from vertical to horizontal wells to capture significant remaining reserves, while eliminating vertical wells along the path of the lateral resulting in reducing surface / environmental footprint and associated costs and liability. In 2022, two horizontal re-entry pilot wells were drilled to assess the technical and economic merits to substantiate a full scale development program. The pilots revealed that converting from re-entry to conventional horizontal would allow for better control of the well. Especially, in these depleted reservoirs where there is higher chance of encountering loss of circulation. Also, gentler build enables optimum operating conditions for pump landing. Based on the these pilots, a 10 horizontal well development program has been initiated by PEI for 2023. The PEI pilots enabled reserves booking of 100 Mbbl TPP reserves per horizontal well, additional PUD locations with total proved (TP) reserves of 1.8 MMbbl and total proved plus probable (TPP) reserves of 2.2 MMbbl. Prospera also exploited uphole zones in these fields with five new recompletions accessing new reserves of 128 Mbbl and 837 MMcf TPP reserves with significant development upside to add new production and reserves.
More significantly, PEI production tested the medium oil property acquired in 2022 by free flow average rate of 300 bpd at 6% watercut over 8 hours. This substantiated additional TPP reserves of 189 Mbbl. This test along with geological and seismic delineation have initiated a 2023 development program of eight vertical / directional wells. These wells will access new pool reserves and provide PEI with new incremental medium oil production, improving corporate production and margin. A pressure transient analysis or well test interpretation has not been carried out. Hence, the data should be considered as preliminary until such analysis or interpretation has been done. Furthermore, the test results are not indicative of long-term performance or ultimate recovery.
Prospera’s 2022 testing with pilot wells has initiated the drilling of ten horizontals in the core Saskatchewan assets and the 8 vertical / directional wells in the medium oil property. Further, PEI also have planned to pilot pressure support to improve recovery of the significant remaining reserves.
2022 Reserve Report Highlights:
• 53% percent increase in TPP reserves from 2,808 to 4,306 Mboe at 95% liquids
• 30% increase in before tax cash flow NPV@10% from $56.2 million to $72.5 million
• The TPP reserve life index also lengthened from 23.0 to 28.4 years
• PEI elected to apply modest price of 79$/bbl (WCS) for the estimation of NPV, allowing for substantial NPV appreciation if oil price sustains
NI 51-101 Table 2.1.1
The following table discloses, in the aggregate, the Corporation’s gross and net proved and probable reserves, estimated using forecast prices and costs by product type. “Forecast prices and costs” means future prices and costs in the InSite Report that are generally accepted as being a reasonable outlook of the future or fixed or currently determinable future prices or costs to which the Corporation is bound.
Gross reserves are the working interest share only. Net reserves are the working interest gross reserves plus all royalty interest reserves receivable less all royalty burdens payable. Conventional natural gas (solution) includes all gas produced in association with light, medium and heavy crude oil.
Product Prices
The InSite base product price forecast, effective January 1, 2023, was used for this evaluation. A copy of which is included in the InSite Report. To estimate actual received prices, adjustments were made to crude oil and by-products prices for quality and transportation tariffs. Similarly, adjustments were made to gas prices for heating value and transportation. It is assumed that the adjustment factors and increments will remain constant throughout the forecasts. Revenue data provided by the Company was used to quantify price adjustments. If such data was unavailable, typical values for the area were used to estimate price adjustments. Risks of political and economic uncertainties could affect future results and could cause results to differ materially from those expressed in this evaluation.
Economic Results
Summarized as follows is the NPV of the Corporation’s future net revenue attributable to the reserves categories previously tabulated, estimated using forecast prices and costs, before deducting future income tax expenses, and without discount and using discount rates of 5%, 10%, 15% and 20%. Future net revenue includes all resource income and is after capital investments, operating expenses, and royalties.
Future operating costs are based on historical data. Wherever unavailable, they were estimated from analogous operations in the vicinity of the properties. The inflation of capital and operating costs is assumed to be 2.0% per annum after 2023.
InSite has included cost estimates of well abandonment and reclamation for all existing wells, regardless of reserves assignment, and undeveloped locations assigned reserves. Estimates have been prepared based on historical costs and published guidance from provincial liability management or rating. It is understood that all abandonment and reclamation costs of wells and facilities have been accounted for by the Company.
After Tax Results
As mandated by NI 51-101, after tax results are shown in the various tables of the InSite Report. After-tax calculations at the company level incorporated tax legislation and tax pool details for the Company, complying with the guidelines and philosophy of NI 51-101 in all material aspects. All future capital cost estimates herein have been categorized by tax pool definitions and used to supplement the year-end tax pool information provided by the Company. The year-end tax pool, as provided by the Company, is summarized below:
• Canadian Oil and Gas Property Expense (COGPE) 7,259,636
• Canadian Development Expense (CDE) 3,434,117
• Capital Cost Allowance (CCA Class 8,10,13,41,45) 3,156
• Non-Capital Losses (100%) 6,846,004
Qualification
To prepare their evaluation, a technical presentation of properties was made by the Company to InSite. Data required by them was sourced from the Company, industry references and regulatory bodies. Neither field inspection nor environmental review of these properties were conducted by InSite, nor deemed necessary. Generally accepted engineering methods were employed to estimate reserves and forecast production. The InSite Report follows the Practice Standards and Guidelines of the Association of Professional Engineers and Geoscientists of Alberta (APEGA) and adheres in all material aspects to the business practices, evaluation procedures, and reserve definitions contained within NI 51-101 and the COGEH Handbook.
