Aurex Energy Corp. — Audit Report / Information 2020

Feb 11, 2021

AUREX ENERGY CORP.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION (FORM 51-1-1F1)

Part 1-Date of Statement

This statement of reserves data and other oil and gas information is based on the MKM Engineering Reserves Report dated June 8, 2020. The effective date of the report is January 1, 2020.

Part 2-Disclosure of Reserves Data

In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, the tables contained in this filing are a summary of the oil, natural gas and natural gas liquids reserves and the value of future net revenue of Aurex Energy Corp. (the “Corporation” or “Aurex”), held in its 100%owned US subsidiary Gas Tap Corp. This filing is based on the report as evaluated by MKM Engineering (“MKM”) effective as at January 1, 2020 “Appraisal Of Certain Oil And Gas Interests Located In Hill, Hood, Parker And Tarrant Counties, Texas As Of January 1, 2020” prepared for Aurex Energy Corp., dated June 8, 2020, (the “Reserves Report”). MKM is an independent qualified reserves evaluator and auditor.

The Reserves Report evaluated the reserves of Aurex, a natural resource company with head offices in Saskatchewan, Canada. The assets of Aurex evaluated in the Reserves Reports represent shut-in natural gas reserves located in Texas, USA and are the only oil and gas reserves of the Corporation. The tables below show the reserves and discounted cashflow values for the corporation.

It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Corporation’s reserves estimated by MKM represent the fair market value of those reserves. The recovery and reserve estimates of the Corporation’s oil and natural gas reserves provided are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided.

In preparing their reports, MKM relied upon certain factual information and data furnished by the Corporation with respect to ownership interests, oil, natural gas and natural gas liquids production, historical costs of operation and development, product prices, agreements relating to current and future operations, sales of production, and other relevant data. The extent and character of all factual information and data supplied were relied upon by MKM in preparing their report and was accepted as represented without independent verification. MKM relied upon representations made by the Corporation as to the completeness and accuracy of the data provided and that no material changes in the performance of the properties has occurred nor is expected to occur, from that which was projected in their reports, between the date that the data was obtained for their evaluations and the date of their report, and that no new data has come to light that may result in a material change to the evaluation of the reserves presented in this Form 51-101F1.

The evaluations were conducted within MKM’s understanding of petroleum legislation, taxation and other regulations that currently apply to these interests. However, MKM is not in a position to and did

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not attest to the property title, financial interest relationships or encumbrances related to the Corporation’s licenses.

The evaluations in the Reserves Reports reflect MKM’s informed judgment based on the Canadian Oil and Gas Evaluation Handbook Standards but is subject to generally recognized uncertainties associated with the interpretation of geological, geophysical and engineering data. The reported hydrocarbon resources volumes are estimates based on professional engineering judgment and are subject to future revision, upward or downward, because of future operations or as additional information becomes available.

The following tables are prepared from information contained in MKM’s Reserve Report as of January 1, 2020. Some of the numbers in the following tables may not appear to sum to the stated totals because of rounding in the source tables.

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Disclosure of Reserves Data Breakdown of Reserves (Forecast Case)

Table 2.1.1: SUMMARY OF CRUDE OIL, NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES BASED ON FORECAST PRICES AND COSTS AS AT JANUARY 1, 2020

	Light and Medium Oil	Light and Medium Oil	Shale Natural Gas	Shale Natural Gas	Natural Gas Liquids	Natural Gas Liquids
Reserves Category	Gross (Mbbl)	Net (Mbbl)	Gross (MMcf)	Net (MMcf)	Gross (Mbbl)	Net (Mbbl)
PROVED
Developed Producing	0	0	0	0	0	0
Developed Non-Producing	9	4	2,805	1,122	0	0
Undeveloped	0	0	0	0	0	0
TOTAL PROVED	9	4	2,805	1,122	0	0
PROBABLE	56	48	21,499	17,795	0	0
TOTAL PROVED + PROBABLE	65	52	24,304	18,917	0	0

Table 2.1.2: NET PRESENT VALUE OF FUTURE NET REVENUES BASED ON FORECAST PRICES AND COSTS AS AT JANUARY 1, 2020

	Before Income	Before Income	Taxes Discounted at(%/year)	Taxes Discounted at(%/year)	Taxes Discounted at(%/year)
Reserves Category	0% (US$000’s)	5% (US$000’s)	10% (US$000’s)	15% (US$000’s)	20% (US$000’s)
PROVED
Developed Producing	0	0	0	0	0
Developed Non-Producing	1,392	1,173	995	849	727
Undeveloped	0	0	0	0	0
TOTAL PROVED	1,392	1,173	995	849	727
PROBABLE	43,430	27,630	19,408	14,369	10,960
TOTAL PROVED + PROBABLE	44,822	28,803	20,403	15,218	11,687

	After Income Taxes Discounted at(%/year)	After Income Taxes Discounted at(%/year)	After Income Taxes Discounted at(%/year)	After Income Taxes Discounted at(%/year)	After Income Taxes Discounted at(%/year)
Reserves Category	0% (US$000’s)	5% (US$000’s)	10% (US$000’s)	15% (US$000’s)	20% (US$000’s)
PROVED
Developed Producing	0	0	0	0	0
Developed Non-Producing	1,099	934	797	684	589
Undeveloped	0	0	0	0	0
TOTAL PROVED	1,099	934	797	684	589
PROBABLE	34,309	21,962	15,512	11,544	8,845
TOTAL PROVED + PROBABLE	35,408	22,896	16,309	12,228	9,434

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Table 2.1.3: TOTAL FUTURE NET REVENUE UNDISCOUNTED BASED ON FORECAST PRICES AND COSTS AS AT JANUARY 1, 2020

Reserves Category	Revenue (US$)	Royalties (US$)	Operating Costs (US$)	Development Costs (US$)	Abandonment and Reclamation Costs(US$)	Future Net Revenue Before Tax (US$)	Income Tax (US$)	Future Net Revenue After Tax (US$)
Total Proved	9,605,270	5,762,910	1,650,810	592,590	207,310	1,391,650	292,250	1,099,400
Proved + Probable	98,679,270	21,782,340	24,749,330	6,738,610	587,620	44,821,370	9,412,490	35,408,880

Table 2.1.4: TOTAL FUTURE NET REVENUE (DISCOUNTED AT 10%/YR) BY PRODUCT TYPE BASED ON FORECAST PRICES AND COSTS AS AT JANUARY 1, 2020

UNITED STATES

	Light and Medium Oil	Light and Medium Oil	Shale Natural Gas	Shale Natural Gas
Reserves Category	US$	Unit Value (US$/bbl)	US$	Unit Value (US$/Mcf)
PROVED
Developed Producing	0	0	0	0
Developed Non-Producing	57,975	16.19	937,165	0.84
Undeveloped	0	0	0	0
TOTAL PROVED	57,975	16.19	937,165	0.84
PROBABLE	826,332	17.15	18,581,398	1.04
TOTAL PROVED + PROBABLE	884,307	17.09	19,518,563	1.03

Notes:

1. “Proved Reserves” are those Reserves that can be estimated with a high degree of certainty to be recoverable. There is a 90% probability that the actual remaining quantities recovered will exceed the estimated Proved Reserves .

1. “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 + Probable Reserves.

2. “Possible Reserves” are those additional Reserves that are less certain to be recovered than Probable Reserves. There is a 10% probability that the actual remaining quantities recovered will equal or exceed the sum of the estimated Proved + Probable + Possible Reserves.

3. “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 (e.g., when compared to the cost of drilling and completing a well) to put the Reserves on production. The developed category may be sub-divided into Producing and Non-Producing.

4. “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

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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.

1. “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.

2. “Undeveloped Reserves” are those Reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling and completing a well) is required to render them capable of production. They must fully meet the requirements of the Reserves category (Proved, Probable, Possible) to which they are assigned and expected to be developed within a limited time.

Part 3-Pricing Assumptions

Item 3.1 :

No Constant Pricing was used for this evaluation.

Item 3.2.1 : Forecast Pricing Used In Estimates

Table 3.2.1: Forecast Prices (US$)

Date	Shale Gas $/MMBTU	Light/Med Oil$/BBL
2020	2.65	61.00
2021	2.86	63.24
2022	3.02	65.55
2023	3.18	67.39
2024	3.25	68.73
2025	3.31	70.11
2026	3.38	71.51
2027	3.45	72.94
2028	3.51	74.40
2029	3.59	75.89
2030	3.66	77.41
Thereafter	2%	2%

Historical hydrocarbon liquid prices were indexed to the monthly average of the daily closing prices received at the Cushing, Oklahoma delivery point. The average difference between the wellhead oil price and the NYMEX price represents adjustments for crude quality, marketing fees, BS&W, transportation costs and purchaser bonuses. These adjustments were applied to the NYMEX prices listed in table above.

Historical natural gas prices were indexed to the monthly Henry Hub prices posted in the Inside FERC publication. Historical prices were indexed for each month of available accounting data. The average difference between the wellhead price and the NYMEX price represents adjustments for BTU content, marketing, and transportation costs. These adjustments were applied to the NYMEX prices listed in table above.

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Item 3.2.2:

The following table details the benchmark reference prices reflected in the reserves data used in this evaluation:

Table 3.2.2: Summary of Pricing and Inflation Assumptions Forecast Prices and Costs

As At January 1, 2020

Year	OIL WTI Cushing (US$/bbl)	Natural Gas US HenryHub(US$/MMBtu)	Inflation Rate %/year
2020	61.00	2.65	2.0
2021	63.24	2.86	2.0
2022	65.55	3.02	2.0
2023	67.39	3.18	2.0
2024	68.73	3.25	2.0
2025	70.11	3.31	2.0
2026	71.51	3.38	2.0
2027	72.94	3.45	2.0
2028	74.40	3.51	2.0
2029	75.89	3.59	2.0
2030	77.41	3.66	2.0
Thereafter	2%/year	2%/year	2.0

Item 3.3.3 :

The pricing assumptions were provided by McDaniel & Associates, Calgary, Alberta, an independent qualified reserves evaluator or auditor.

Part 4-Reconciliation of Changes in Reserves

This being the first NI 51-101 filing, no reserve reconciliation has been completed at this time.

Part 5-Additional Information Relating To Reserves Data

Item 5.1

The Corporation has no undeveloped reserves.

Item 5.2: Significant Factors or Uncertainties Affecting Reserves Data

All of the Corporation’s Reserves are evaluated by MKM Engineering, an independent engineering firm. The Proved and Probable Reserves presented in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered; and, if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the product prices and the costs incurred in recovering these Reserves may vary from the price and cost assumptions in this report. In any case, quantities of Proved and Probable Reserves may increase or decrease as a result of future operations.

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Reserves estimates for individual properties included in this report are only valid when considered within the context of the overall report and should not be considered independently. The future net income and net present value estimates contained in this report do not represent an estimate of fair market values.

The Corporation’s actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements and accordingly, no assurance can be given that any events anticipated by the forward-looking statements will transpire or occur, and if any of them do, what benefits the Corporation may derive therefrom. The reader is cautioned not to place undue reliance on this forward-looking information.

The Corporation anticipates that future development costs associated with its Reserves will be financed through a combination of debt and equity financing and joint venture-type arrangements. At some point in the future, it is anticipated that costs can be partially financed through internally-generated cashflow.

Item 5.2: Information Concerning Abandonment and Reclamation Costs

Table 5.2: ESTIMATED FUTURE ABANDONMENT AND RECLAMATION COSTS FORECAST PRICES AND COSTS AS AT JANUARY 1, 2020

Year	Proved Reserves US$	Proved Plus Probable Reserves US$
2020	0	0
2021	0	0
2022	0	0
2023	43,810	0
2024	44,630	0
2025	67,970	0
2026	0	0
2027	11,870	11,870
2028	0	0
Thereafter	30,030	575,750
Total	207,310	587,620

Item 5.3: Future Development Costs

Table 5.3: ESTMATED FUTURE DEVELOPMENT COSTS

FORECAST PRICES AND COSTS AS AT JANUARY 1, 2020

Year	Proved Reserves US$	Proved Plus Probable Reserves US$
2020	220,960	1,925,860
2021	371,630	4,812,750
2022	0	0
2023	0	0
2024	0	0
Total	592,590	6,738,610

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The Corporation will need to obtain funding to complete the development costs specified above. It is anticipated that this will be achieved through a combination of debt and equity, and joint venture-type arrangements. If the initial work programs are successful, part of the funding could come from internally generated cashflow. The costs of debt and equity financing is anticipated to be at rates currently prevailing in Canada or the US. The cost of a joint venture-type arrangement would be negotiable and unknown at this time. The effect of the costs of the anticipated funding could have a material impact on the revenues and reserves currently being reported.

Part 6-Other Oil and Gas Information

Item 6.1: Oil and Gas Properties and Wells

All the Corporation’s properties and wells (the Corporation is the operator with 100% interest) are located in the state of Texas, USA. The wells are onshore and comprise 9 shut-in natural gas wells, and 1 well waiting on completion. Eight of the wells are horizontal wells and two are vertical wells. The 9 shut-in wells (8 horizontal and 1 vertical) produced from the Newark East Field (the Barnett Shale Formation) and the 1 vertical well is awaiting completion in the Atoka Formation.

The 8 horizontal wells were shut-in in late 2008 and early 2009 and are still connected to pipelines. Of the 2 vertical wells, 1 was shut-in in 2004 and the other drilled in 2004 waiting on completion. The one vertical well not connected to a pipeline is in close proximity to one.

Item 6.1.2: Gross and Net Oil and Gas Wells

Table 6.1: United States-Texas

Texas	Light and Medium Oil	Light and Medium Oil	Natural Gas	Natural Gas
	Gross	Net	Gross	Net
Producing	0	0	0	0
Non-Producing	0	0	10	8
Total	0	0	10	8

Item 6.2: Properties With No Attributed Reserves

The Corporation has no properties with no attributed reserves.

Item 6.2.1: Significant Factors or Uncertainties Relevant to Properties With No Attributed Reserves

Not applicable.

Item 6.3: Forward Contracts

The Corporation has no forward contracts.

Item 6.5: Tax Horizon

The Corporation is not expected to begin paying income tax until after the 2022 fiscal year and is dependent on the ability to raise funding to complete the development costs disclosed in this Form.

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Item 6.6: Costs Incurred

The Corporation did not incur any capital expenditures in 2019 related to the properties. The cost of Aurex Energy Corp.’s acquisition of Gas Tap Corp., which holds the US oil and gas assets was $8,789,942.

Item 6.7: Exploration and Development Activities

The Corporation did not engage in any exploration and development activities in 2019.

Item 6.8: Production Estimates

Table 6.8: Estimated Production For 2020 Forecast Prices and Costs (Undiscounted)

	Proved Reserves	Proved + Probable Reserves
2020 Production(Gross)
Light and medium oil(Mbbl)	1	1
Gas(MMcf)	125	154
NGL(Mbbl)	0	0
Mboe*	22	27
2020 Production(Net)
Light and medium oil(Mbbl)	0	1
Gas(MMcf)	50	100
NGL(Mbbl)	0	0
Mboe*	9	17

*Boe conversion ratio of 6 Mcf to 1 barrel of crude oil is based on an energy equivalency conversion method.

Item 6.9-Production History

The Corporation had no production in 2019.

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ABBREVIATIONS

CRUDE OIL	NATURAL GAS
bbl barrel	Mcf thousand cubic feet
bbls barrels	MMcf million cubic feet
Mbbls thousands of barrels	MMBTU million british thermal units
MMbbls millions of barrels	GJ gigajoule
NGLs naturalgas liquids

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