Fortem Resources Inc | A Gas and Oil Company - Attention: … · 2019-05-07 · APEX GLOBAL ENGINEERING INC. Page 2 either the Company’s technical representatives or on behalf of

April 05, 2018

Fortem Resources Inc. Suite 1588-609 Granville Street Vancouver, BC V6C 1X6

Attention: Michael Caetano (COO- Director)

RE: Moenkopi Play, Interests held by Fortem Resources Inc.

REPORT Pursuant to your request and authorization, Apex Global Engineering Inc. herein after referred to as “Apex”, has prepared this preliminary Reserve and Resource Study of the property known as “Dragon-Moenkopi”, located in western Utah, USA (the “Report”). The ‘Dragon-Moenkopi’ interests are held within a wholly owned subsidiary of Fortem Resources Inc., known as ‘Black Dragon Energy LLc’. All references to the ‘Black Dragon Energy LLc’ interests referred to in this report will be considered to be owned by Fortem through its subsidiary. This Report has been prepared for the exclusive use of Fortem Resources Inc., herein after referred to as “The Company”, for corporate reporting purposes pursuant to Section 5.2 and Section 5.9 of National Instrument 51-101 (“NI 51-101”). In addition Apex has included reference to reserves, resources and net present values for two additional Fortem projects with previously submitted reports. These additional projects are located in the province of Alberta, Canada and are referred to as the ‘Godin Project’ and the ‘Compeer Project’. The Godin project is a heavy oil project held within another wholly owned subsidiary of Fortem Resources Inc., called ‘Colony Energy ‘. The ‘Compeer Project’ is a conventional oil project held in another wholly owned subsidiary called ‘Big Lake Energy Inc.’ The effective date of this evaluation is March 31, 2018

SCOPE OF WORK This report is intended to describe and quantify the Reserves and Contingent Resources contained within the lands owned by The Company, on a preliminary basis and in advance of a more detailed report once all of the data has been reviewed and a development plan has been prepared. This Report contains forward looking statements. Information concerning reserves may also be deemed to be forward looking as estimates imply that the reserves may be produced now and or in the future and reserves described can also be profitably produced in the future.

OWNER CONTACT AND PROPERTY INSPECTION Apex has visited with the Company’s management and representative to discuss the material for this report. Apex has gone through the Company land records which were provided, and verified the ownership of the lands to the extent of the accuracy of the records provided. Further, Apex has reviewed geological, geophysical and engineering data which was provided and found that a significant amount of the data was not generated by the Company, but was generated by third parties who either had prior ownership in the lands and were the responsible operators at the time of the data acquisition, or was interpreted by third parties on behalf of

APEX GLOBAL ENGINEERING INC. Page 2

either the Company’s technical representatives or on behalf of the previous owner and operator of the lands and assets. No field inspection was carried out by any Apex staff as it was not considered to be required for the preparation of this report.

ASSUMPTIONS AND LIMITING CONDITIONS This preliminary valuation is limited to the following scope at this time:

1. Reviewing and introducing the Moenkopi TSX member reserves associated with and proximal to the Wellington Flats 15-11-18E well in the project area;

2. Presenting the Contingent Resources associated with the Fortem Moenkopi Project and within four (4) members of the Moenkopi Group (the TSX member and the Sinbad, Torrey A & B members).

The reserve definitions utilized are from COGEH and applied as per NI51-101.

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied projects are not yet considered mature enough for commercial development due to one or more contingencies. The Contingent Resources are defined as per Section 2 of COGEH.

These statements are based on current expectations that involve a number of risks and uncertainties, which could cause the actual results to differ from those anticipated. These risks include, but are not limited to: the underlying risks of the oil and gas industry (i.e. operational risks in development, exploration and production; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to costs and expenses, and political and environmental factors), and commodity price and exchange rate fluctuation). Apex with input and direction from Fortem is in the process of creating a full development plan for Fortem for this Utah project. With respect to all information provided to Apex regarding product marketing, transportation, and processing arrangements, Fortem confirms that Fortem have disclosed to Apex all anticipated changes, terminations, and additions to these arrangements that could reasonably be expected to have a material effect on the evaluation of The Company's resource and future net revenues.

Table 1 Resources Classification Framework


The main contingencies relate to successfully completing and testing new wells, the presence of sufficient permeability and capacity of the reservoir to produce economically along the mapped trends, and the refining and marketing as there are no current plans in place.

A BOE conversion ratio of 6 Mscf: 1 barrel has been used within this Report. This conversion ratio is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Michael Kamis P. Eng., Principal, Apex Global Engineering Inc.


Reserves and Resource Report, Moenkopi Formation Utah

For Fortem Resources Inc.

Effective Date March 31, 2018

APEX GLOBAL ENGINEERING INC.

Applied Petroleum Engineering Expertise


Contents

REPORT ................................................................................................................................ 1

SCOPE OF WORK ................................................................................................................. 1

OWNER CONTACT AND PROPERTY INSPECTION ............................................................ 1

ASSUMPTIONS AND LIMITING CONDITIONS ..................................................................... 2

INDEPENDENT ENGINEER’S DECLARATION ......................................................................... 9

CERTIFICATION OF QUALIFICATION: Michael Kamis ............................................................10

CERTIFICATION OF QUALIFICATION: Robert Martin .............................................................11

CERTIFICATION OF QUALIFICATION: Douglas MacLellan .....................................................12

CERTIFICATION OF QUALIFICATION: Hollie Pearce ..............................................................13

SUMMARY ...............................................................................................................................14

Wellington Flats Well .............................................................................................................14

LAND TENURE .........................................................................................................................16

LAND SUMMARY TABLE .....................................................................................................16

ACQUISITION TERMS: .........................................................................................................17

PROPOSED WORK PROGRAMME: ........................................................................................17

Economic Development Plan Assumptions ...........................................................................18

GEOLOGICAL REVIEW: ..........................................................................................................22

Introduction ...........................................................................................................................22

Location .................................................................................................................................23

Previous Work .......................................................................................................................24

Uinta Basin Stratigraphy ........................................................................................................25

Black Dragon Member of Moenkopi Formation .............................................................. 27 Sinbad Limestone Member of Moenkopi Formation ....................................................... 27 Torrey Member of Moenkopi Formation ......................................................................... 27 Uinta Basin Structural Setting ........................................................................................ 27

Reservoir Geology .................................................................................................................30

TXS Sand ...................................................................................................................... 30 Sinbad Dolomite ............................................................................................................ 30 Torrey A & B Sandstones .............................................................................................. 30

Oil Generation and Migration .................................................................................................31

Source ........................................................................................................................... 31 Migration ........................................................................................................................ 31 Seal ............................................................................................................................... 31


Petroleum Potential of the Fortem Resources Lands Permit ..................................................31

Proven Reserves ........................................................................................................... 32 Contingent Resources Development Pending ................................................................ 36 TXS Sandstone .............................................................................................................. 36 Contingent Resources Development on Hold................................................................. 37 Prospective Resources .................................................................................................. 41

DEFINITIONS OF RESERVES, CONTINGENT AND PROSPECTIVE RESOURCES, AND METHODOLOGY ......................................................................................................................43

Deterministic and Probabilistic Methods ................................................................................48

a. Deterministic Method ................................................................................................. 48 b. Probabilistic Method ................................................................................................... 48 c. Comparison of Deterministic and Probabilistic Estimates ........................................... 48 d. Application of Guidelines to the Probabilistic Method ................................................. 49

Glossary....................................................................................................................................51

Partial Bibliography ...................................................................................................................53

APPENDIX 1: Wellington Flats 15-11 Composite Log and Tully 16-9-36D ................................54

APPENDIX 2:Wellington Flats 15-11 Production Chart .............................................................55

APPENDIX 3: Fortem Resources Lands-1 ................................................................................56


Figure 1 Fortem Resources Lease Locations. ..................................................................................... 17 Figure 2 Location of Fortem Resources Lands in Utah ...................................................................... 23 Figure 3 TXS Net Pay Overlaid by Fortem Resources Land (left), Sinbad Net Pay Overlaid by Fortem Resources Land. ......................................................................................................................... 23 Figure 4 Torrey A Net Pay Map overlaid by Fortem Resources land leases (left), Torrey B Net Pay Map overlaid by Fortem Resources land leases (right) .............................................................. 24 Figure 5 Location of the Fortem Resources Lands in the Uinta Basin ............................................ 24 Figure 6 Regional Structural Framework 2D seismic ......................................................................... 25 Figure 7 Stratigraphic Column of the Moenkopi Formation ............................................................... 26 Figure 8 Main Oil and Gas Basins in Utah and Western Colorado .................................................. 28 Figure 9 The dominant structure in the Fortem lands is the plunging nose of the San Rafael Swell ........................................................................................................................................................... 29 Figure 10 Fortem Resources area of exploration ................................................................................ 30 Figure 11 Wellington Flats 15-11-18E Vertical Section displaying directional survey ................... 33 Figure 12 Gamma Ray Neutron Density log TXS Sandstone - Wellington Flats 15-11 18E ........ 34 Table 1 Resources Classification Framework ............................................................................ 2 Table 2 Fortem Resources Lands Proven and Probable Reserves (Volumetric Analysis) .........15 Table 3 Fortem Resources Land Permit Contingent Tight Oil Resources Unrisked and Risked 15 Table 4 Fortem Resources Land Area ......................................................................................16 Table 5 Fortem Resources Lands Permit Net Acreage .............................................................17 Table 6 Moenkopi Capital Expenditure Assumptions ................................................................19 Table 7 Moenkopi Price Model ..................................................................................................19 Table 8 Moenkopi Formations Production Assumptions ............................................................19 Table 9 Moenkopi Operating Costs ...........................................................................................20 Table 10 TXS Total Proved & Probable Reserves (Tight Oil) from Economic Modelling ............20 Table 11 TXS Proven + Probable Reserves Before Tax Cash Flow NPV ..................................20 Table 12 Contingent Resource (Development Pending/On Hold) Tight Oil Summary (MBBL) ...21 Table 13 Moenkopi Contingent Resource NPV (On BT Cash Flow) ..........................................21 Table 14 Land Analysis for Proven and Probable Additional Land Interests ..............................21 Table 15 Total Future Net Revenue Reserves ..........................................................................21 Table 16 Total Future Net Revenue Resources ........................................................................21 Table 17 Fortem Resources Lands Permit Proven Reserves (Volumetric) ................................35 Table 18 Parameters to Determine Proven Reserves ...............................................................35 Table 19 Chance of Development Risk Parameters ..................................................................37 Table 20 TXS Sandstone Chance of Development ...................................................................37 Table 21 Moenkopi Contingent Resource Development Pending ..............................................37 Table 22 Chance of Development Risk Parameters .................................................................38 Table 23 Sinbad Dolomite Chance of Development ..................................................................38 Table 24 Torrey B Chance of Development Risk Parameters ..................................................39 Table 25 Torrey B Chance of Development ..............................................................................39 Table 26 Torrey A Chance of Development Risk Parameters ...................................................39


Table 27 Sinbad Dolomite Chance of Development ..................................................................39 Table 28 Moenkopi Contingent Resource Development on Hold .............................................40 Table 29 Sinbad Chance of Discovery Risk Parameters ..........................................................41 Table 30 Sinbad Dolomite Chance of Discovery .......................................................................41 Table 31 Torrey A Chance of Discovery Risk Parameters .........................................................41 Table 32 Torrey A Chance of Discovery ....................................................................................42 Table 33 Torrey B Chance of Discovery Risk Parameters .........................................................42 Table 34 Torrey B Chance of Discovery ....................................................................................42 Table 35 Moenkopi Contingent Resource Development on Hold ..............................................43 Table 36 Resources Classification Framework ..........................................................................43 Table 37 Resources Classification Framework with Project Maturity Sub-classes .....................46


INDEPENDENT ENGINEER’S DECLARATION This is to declare that APEX GLOBAL ENGINEERING INC. acknowledges that it has prepared this Evaluation of Fortem Resources Inc. interests in certain properties in the Uinta Basin, Utah, USA;

At the effective date of this presentation, Chamonix Canada Inc., a company owned by the ‘Kamis Family Trust’, held 353,250 shares in Fortem Resources Inc. Michael Kamis is the ‘Trustee’ on behalf of the Trust. The shares were issued as part of a debt settlement.


CERTIFICATION OF QUALIFICATION: Michael Kamis

I, Michael Kamis, Professional Engineer, Suite 820, 906 - 12th Ave SW, Calgary, Alberta, Canada T2R

1K7, Canada, HEREBY CERTIFY:

1. That I am the principal of APEX GLOBAL ENGINEERING INC., and that I participated in

the preparation of a Resource Study evaluating the interests of Fortem Resources Inc., in the

Fortem Resources Lands, Utah. Effective date of this report is March 31, 2018.

2. At the effective date of this presentation, Chamonix Canada Inc., a company owned by the

‘Kamis Family Trust’, holds 353,250 shares in Fortem Resources Inc. Michael Kamis is the

‘Trustee’ on behalf of the Trust. The shares were issued as part of a debt settlement.

3. That I attended the University of Wyoming and that I graduated with a Bachelor of Science

Degree in Petroleum Engineering in 1977; and that I have in excess of thirty-nine (39) years of

Petroleum Engineering/Geological studies relating to Western Canada, the United States and

international oil and gas fields.

4. That I have been a member of SPE (Society of Petroleum Engineers) since 1975 and continue as

a member in good standing, (member number 0315085).

5. That I have been a member in good standing with APEGA ( Association of Professional

Engineers and Geoscientists of Alberta) since September 1979, membership number 28516.

6. No field inspection was carried out, as it was not within the scope of the evaluation.

Michael Kamis, P.Eng.

April 05, 2018


CERTIFICATION OF QUALIFICATION: Robert Martin

I, Robert Martin, Professional Geologist, Suite 820, 906 - 12th Ave SW, Calgary, Alberta, Canada T2R

1K7, HEREBY CERTIFY:

1. That I am an Associate of APEX GLOBAL ENGINEERING INC., and that I participated in the

preparation of a Resource Study evaluating interests of Fortem Resources Inc., in the Fortem

Resources Lands, Utah. The Effective date of this report is March 31, 2018.

2. That I do not have any direct or indirect interest in the properties or securities of Fortem Resources

Inc. or its Assets.

3. That I have in excess of thirty-nine (39) years of oil & gas experience relating to petroleum and

minerals exploration & exploitation in Canada and internationally.

4. That I am a graduate in 1977 of McGill University with Bachelor of Science Degree (Honours)

Geology and I am a Professional Geologist with the Association of Professional Engineers,

Geoscientists of Alberta (APEGA), membership number 30938.


Robert Nicholas Martin, P.Geol.

April 05, 2018


CERTIFICATION OF QUALIFICATION: Douglas MacLellan

I, Doug MacLellan, Professional Engineer, Suite 820, 906 - 12th Ave SW, Calgary, Alberta, Canada T2R

1K7, Canada, HEREBY CERTIFY:

1. That I am an Associate of APEX GLOBAL ENGINEERING INC., and that I participated in the

preparation of a Resource Study evaluating interests of Fortem Resources Inc., in the Fortem

Resources Lands, Utah. Effective date of this report is March 31, 2018.

2. That I do not have nor do I expect to receive any direct or indirect interest in the properties or

securities of Fortem Resources Inc. or its Assets.

3. That I attended the University of Saskatchewan and that I graduated with a Bachelor of Science

Degree in Chemical Engineering in 1973; and that I am a Registered Professional Engineer in the

Province of Alberta; and that I have in excess of forty-four (44) years of oil & gas experience relating

to Western Canada, the United States and international oil and gas fields.

4. That I have been a member in good standing with APEGA (Association of Professional Engineers,

Geoscientists of Alberta), member #32095, since September, 1977.

5. That I have been a member in good standing with SPE (Society of Petroleum Engineers), member #

1114792, since 1986.


Douglas Murray MacLellan, P. Eng

April 05, 2018


CERTIFICATION OF QUALIFICATION: Hollie Pearce I, Hollie Pearce, Geoscientist in Training, Suite 820, 906 - 12th Avenue SW, Calgary, Alberta, T2R 1K7, Canada, HEREBY CERTIFY:

1. That I am an Associate of APEX GLOBAL ENGINEERING INC., and that I participated in the preparation of a Resource Study evaluating interests of Fortem Resources Inc., in the Fortem Resources Lands, Utah. The Effective date of this report is March 31, 2018.

2. That I do not have any direct or indirect interest in the properties or securities of Fortem Resources Inc., or its Assets.

3. That I graduated from Mount Royal University in April of 2016 with Bachelor of Science Degree in Geology.

4. That I have worked with APEX from April 2013 to April 2016 as a student (part-time), and from May 2016 to present (full-time) gaining oil and gas geological experience in Canada and the United States.

5. I am a Geoscientist in Training with APEGA (Association of Professional Engineers, and Geoscientists of Alberta) and have been a Member since January, 2017; membership # 167365.


Hollie Pearce, GIT

April 05, 2018


SUMMARY The Company owns a 75% working interest in approximately 150,178 acres in the Moenkopi Project. The TXS member trend is located over an estimated 33,920 acres leased to Fortem and its partner. The Sinbad member is mapped as having net pay over about 120,640 acres with Fortem working interest and both the Torrey A and B members are seen in the same lands.

In preparing this preliminary Reserve and Resource Summary for Fortem Resources Inc. to evaluate the Moenkopi Group in the Company lands in Utah, the focus was on the Wellington Flats 15-11-18E well, drilled in 2012 to a total depth of 9,500 feet (TVD 5,900 feet) and the nearby Grassy Trail Field. The Company has no ownership in the Grassy Trail Field; it serves as an analog field to the Moenkopi.

Wellington Flats Well The Wellington flats well produced oil and natural gas from the TXS member of the Moenkopi Group. There was no production from the Sinbad member, the Torrey A and the Torrey B members in the Wellington Flats well but in the nearby Grassy Trail Field the Sinbad is the main producer with minor production from the Torrey A and B. Production from the Wellington Flats 15-11-18E well consisted of 13,390 barrels of oil and 90,873 MCF of solution gas. All four members were penetrated by the 15-11 well. The section surrounding the 15-11 well has been given reserves by Apex; 50% Proven Developed Non-Producing (PDNP) and 50% Proven Undeveloped (PUD), both in the TXS member within the section it was drilled, i.e. section 11. Six (6) sections surrounding section 11 containing the 15-11 well have been given Probable reserves in the TXS member as shown in Figure 1. Contingent Resources have been ascribed to the three remaining members contained within the 15-11 section.

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations , but the applied projects are not yet considered mature enough for commercial development due to one or more contingencies.

This Report contains forward looking statements. Information concerning Resources may also be deemed to be forward looking as estimates imply that the Resources described can be profitably produced in the future.

These statements are based on current expectations that involve a number of risks and uncertainties, which could cause the actual results to differ from those anticipated. These risks include, but are not limited to: the underlying risks of the oil and gas industry: operational risks in development, exploration and production; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of resources estimates; the uncertainty of estimates and projections relating to costs and expenses, political and environmental factors; and commodity price and exchange rate fluctuation.


Table 2 Fortem Resources Lands Proven and Probable Reserves (Volumetric Analysis)

TXS Sandstone

FORTEM GROUP ACREAGE Proven Reserves (Barrels) Probable

Reserves (Barrels)

Proven Non Producing Proven Undeveloped

Group Gross (100% WI) 210,464 210,464 2,218,855 Fortem WI (75% ) 157,848 157,848 1,664,141

Proven Developed Non Producing and Undeveloped Reserves were assigned to section 18 Township 15 Range 11 because the well Wellington Flats 15-11-18E, was horizontally drilled and completed in the TXS Unit of the Black Dragon Member of the Moenkopi Formation in 2013. Probable Reserves were assigned in six sections on trend with the Wellington Flats 15-planters11-18E well in the TXS sand because of mapping based upon existing well control. The TXS reservoir and the other productive members of the Moenkopi are assumed to have dual porosity and permeability based upon evidence of fracturing in the Grassy Trails Field and in the Wellington Flats 15-11-18E well. Matrix porosity is low in all the members and they all require horizontal drilling and artificial fracturing to produce. By definition these reservoirs are all considered to be “Unconventional Tight Oil”. Flow rates in the Wellington Flats 15-11-18E well planterswere adversely influenced by the poor completion techniques. The Wellington Flats 15-11 well produced oil at an initial production rate of 150 BOPD.

Contingent Tight Oil Resources, Development Pending (as per COGEH Volume 2, Section 2.4.8, Figure 2.3) were assigned to the rest of the lands where the TXS sand exceeds sixteen (16) feet of net pay on Fortem Resources Land holdings. The Proven and Probable Reserves were subtracted from the Contingent Resource for the TXS Sandstone. The Resource volumes in the TXS Sandstone are defined in this Report as “Contingent Unconventional Tight Oil Resources- Development Pending” because the project could be developed if adequate funding were available. Re-entry of the Wellington Flats 15-11 well is expected within a reasonable time period, pending funding. Once financing is in place, the Chance of Development of the Project will be easier to assess.

The Sinbad Dolomite, the Torrey “B’ and the Torrey “A” produce in the nearby Grassy Trails Field originally discovered in 1984. The Sinbad Dolomite, Torrey A and B Members are considered to have greater risk of development as there is little offsetting commercial production. Two wells have been identified as producing from the Torrey A Member; these are located in the Grassy Trail field. To classify the oil volumes in a Resource Development category other than “Contingent UnConventional Tight Oil Resources- Development on Hold” would require a greater amount of data and information than is available to Fortem Resources Inc. Horizontal drilling and hydraulic fracturing of these Moenkopi Members increased production when tried in the 1990’s in the Grassy Trail Field. Significant further appraisal will be required.

Table 3 Fortem Resources Land Permit Contingent Tight Oil Resources Unrisked and Risked

Fortem Working Interest: 75.00%


Moenkopi Contingent Resources Unrisked Development Pending

Risked Contingent Resources

Fortem Net Risked

Contingent Resource

Gross (100% WI) Unconventional Tight Oil Resources (MMBbls)

Discovered PIIP Contingent Unconventional

Tight Oil Resources- Development Pending

C.O.Dev

Member Low

Estimate (1C)

Best Estimate

(2C)

High Estimate

(3C)

Low Estimate

(1C)

Best Estimate

(2C)

High Estimate

(3C)

Best Estimate

(2C)

Best Estimate

(2C)

Best Estimate

(2C) TXS Sandstone 70.0 114.7 188.0 10.1 20.7 40.2 66% 13.6 10.2

Total 70.0 114.7 188.0 10.1 20.7 40.2 13.6 10.2

Moenkopi Contingent Resources Unrisked

Risked Contingent Resources

Fortem Net Risked

Contingent Resource


Development On Hold


Tight Oil Resources- Development on Hold

C.O.Dev

Low Estimate

(1C)

Best Estimate

(2C)

High Estimate

(3C)

Low Estimate

(1C)

Best Estimate

(2C)

High Estimate

(3C)

Best Estimate

(2C)

Best Estimate

(2C)

Best Estimate

(2C) Sinbad 61.0 109.1 195.3 5.8 11.4 22.5 57% 6.5 4.9

Torrey B 93.7 160.8 275.8 10.0 19.0 35.0 38% 7.3 5.5 Torrey A 105.0 203.0 391.0 11.0 23.0 47.0 34% 7.7 5.8

Total 259.7 472.9 862.1 26.8 53.4 104.5 21.5 16.2

LAND TENURE The Company has a 75% working interest located in Utah’s southern Uinta Basin. The Moenkopi land confined within the “Dragon” and “Spitfire” units (as shown in Figure 1), contain both BLM (Bureau of Land Management) lands and State land. As shown in Table 4, The Company holds 196,385.11 gross acres (147,288.83 net acres) of Federal Lands and 3,852.41 gross acres (2,889.31 net acres) of State Lands. The state lands held by Fortem are significantly less than the Federal lands. The total gross acreage held by Fortem is 200,237.41 acres, with a net acreage of 150,178.06 acres. The Tables below summarize The Company’s Land Interests in the south Uinta Basin.

LAND SUMMARY TABLE Table 4 Fortem Resources Land Area

Fortem Resources Lands Permit Area Block Sq. Km Sq. Miles Gross Acres

Black Dragon Federal Lands 794.74 1.24 196,385.11 Black Dragon State Lands 15.59 6.02 3,852.41 TOTAL 810.33 312.87 200,237.41


Table 5 Fortem Resources Lands Permit Net Acreage

Undeveloped Acres Gross Acres Net Acres Average W.I. Black Dragon - Fortem Resources Lands Permit Area 200,237.41 150,178.06 75% TOTAL 200,237.41 150,178.06 75%

ACQUISITION TERMS: The Fortem Resources Lands Permit totals 150,178.06 net acres (607.75 km2) and is the only Exploration Permit evaluated in this Report.

Figure 1 Fortem Resources Lease Locations.

PROPOSED WORK PROGRAMME: The Fortem programme involves development of all four (4) hydrocarbon bearing reservoirs within the Moenkopi Group; the Torrey A, the Torrey B, the Sinbad and the TXS formations. A great deal of engineering and geological background work has been done to assess the project area. From the testing of the Wellington Flats 15-1811E well, it was decided that Section 18 had Proven reserves in the TXS. Half of the section was deemed Proven Developed and the other half Proven Undeveloped. Surrounding Section 18 there were six sections that were deemed Probable reserves in the TXS. Development of the TXS in this area will be part of the Phase 1 exploitation program. The further development of another 20 sections of TXS involves the same scheme of a 4 well horizontal pad per section. These 20 sections as mentioned earlier are classified as Contingent Resources-Development Pending. Costs and assumptions of the program will be further discussed in a following sub-section on assumptions. The existing well 15-18-11E will undergo a workover followed by the drilling of one proved developed horizontal and two proved undeveloped horizontal wells. The initial drilling will be undertaken with one


drilling rig. The wells should initially require two weeks to drill and complete and eventually be optimized to an eight day program for each well. The wells should be on-stream and have production trucked within three weeks from the spud date. The first field work for drilling the wells will start July 1, 2018 with the first rig, and in September 2018, a second rig will be moved in to assist in the program.

Once section 18 is drilled, then development begins on the six Probable Reserve sections surrounding section 18. These sections have their 24 wells drilled by January 2019. This development work is then followed with the drilling of a section of the “Contingent Resource Development On Hold” Torrey A and Torrey B wells. Since they lie over each other, Torrey A and B development will proceed on the same section including a total of 24 wells for each formation. In addition, the first Sinbad section (Contingent Resources –Development On Hold) will be drilled up with 4 wells at the same time as another 4 wells are drilled in the same section for the TXS Contingent Resource Development Pending area. There are ten (10) sections that contain both the TXS and the Sinbad, both containing the Contingent Development Pending oil resources. These common ten sections will then be drilled concurrently before the rest of the Torrey A and B formation is drilled up. In total, there are 27 sections of TXS to be drilled, including one section of Proved Reserves, 6 sections of probable reserves and 20 sections of Contingent resources. There are actually 32 sections mapped currently that contain developable TXS with a cutoff of net pay great than 16 feet. However, the TXS has a risk success factor of 68% and therefore we are estimating a resulting 20 developable sections. The Sinbad has 18 section of Contingent Resources of which 10 sections have the TXS formation in common after utilizing a 50% success factor on the available 20 sections with developable pay. Lastly, the remaining Torrey A and B are to be drilled. The Torrey A has a 38% success factor and has 15 viable developable sections, resulting in a planned development of 6 sections. The Torrey B is similar with 15 sections and a 34% success factor. This will result in the development of 6 sections of Torrey B defined as Contingent Resources Development on Hold. There are another 68 sections of Sinbad potentially developable as Prospective Resource.

In addition to the drilling of the development wells, the plan projects that we will require a battery to process the oil for every 32 wells. This ultimately will require 7 batteries that have been included in the development model.

The placement of each well ultimately will require some assistance from processed geophysical work. The wells should be more successful if they are placed where they can take advantage of the insitu stress regime where hydraulic fracturing can be optimized. This will be best done with the geophysical model interpretations of the stress regimes. This work is underway right now and the first phase should be completed over the next month. This geophysical work will ultimately reduce our development risk by allowing Fortem to place the wells more accurately for better well production.

Economic Development Plan Assumptions There are 500 wells to be drilled on the lands within the Moenkopi area within the four formations to be developed. These wells are to be drilled over a two and a half year period


along with the construction and placement of seven batteries, the costs associated with the wells and batteries is shown below in the following table and has been estimated relative to experience with drilling and fracturing both in Canada and in the United Sates.

Table 6 Moenkopi Capital Expenditure Assumptions

Category Quantity Cost ($M) Total Cost ($M) Torrey A Well (D&C) 24 $700 $16,800 Torrey B Well (D&C) 24 $700 $16,800 Sinbad Well (D&C) 82 $800 $65,600

TXS well (D&C) 110 $800 $88,000 TXS 1st Well (D&C) 1 $1,500 $1,500

Wellington Flat Workover 1 $200 $200 Battery 7 $2,000 $14,000

TOTAL CAPITAL $202,900 Abandonment Wells 242 $30 $7,260

Abandonment Batteries 7 $100 $700 TOTAL ABANDONMENT (Uninflated) $7,960

The produced oil from the wells in this project is 37 API oil. It is sold to refineries in the near-by area. Pricing is determined and forecast based on sales in the area and changes relative to the US and world markets, the price within the model is as shown in Table 7 below.

Table 7 Moenkopi Price Model

YEAR Base Price Paraffin Differential NET PRICE $/BBL $/BBL $/BBL

2018 57 $7.00 $50.00 2019 60 $7.00 $53.00 2020 62 $7.00 $55.00 2021 66 $7.00 $59.00 2022 69 $7.00 $62.00 2023 72 $7.00 $65.00 2024 75 $7.00 $68.00 2025 78 $7.00 $71.00 2026 81 $7.00 $74.00 2027 84 $7.00 $77.00

The forecasted well production was based on the evaluation of producing wells in the Grassy Trails field and other wells with similar characteristics and based on the depth of production experience within this office. The initial production rates for each horizon are shown in the following table with the forecasted declines and the estimated ultimate cumulative production.

Table 8 Moenkopi Formations Production Assumptions

Production Formation Initial Rate (IP) Initial Decline Cumulative Forecasted Production/Well

BOPD/well % MBBLS Torrey A 60 20 86.8 Torrey B 60 20 86.8


Sinbad 150 50% for 6 mos. then 20 192.2 TXS 150 50% for 6 mos. then 20 192.2

Table 9 Moenkopi Operating Costs

Operating Costs for Moenkopi Wells

Variable Op Costs Trans./Handling $/bbl Esc. 1.5%/yr $/bbl Esc. 1.5%/yr

Initial 12.00 3.00 After 6 mos. 12.00 1.00 - 1.25

Fortem Resources Inc. is a partner with Liberty Petroleum in the Moenkopi project and has a 75% working interest in the joint lands. On average they have a 15% lessee royalty to be paid and thus Fortem has a 63.75% net revenue interest. This was assumed in the economic model for the development plan for all wells. Currently the Fortem Group does not own all of the acreage on the sections that are categorized as Proven and Probable reserves. The Fortem Group has 1,879 acres of the 4,480 acres covered with those seven (7) sections. Their ownership for the wells and production was calculated ratioing the acreage owned in each section by the Fortem Group over the total acreage in each section.

With the full model developed the resulting economics for the development plan are shown in the following tables with values attached to the reserves portion of the plan and values attached to the Contingent Resource portion of the plan.

Table 10 TXS Total Proved & Probable Reserves (Tight Oil) from Economic Modelling

WI (MBBL) Net WI (MBBL)

Total Proved Developed (Mbbl) 197.8 168.1 Total Proved Undeveloped (Mbbl) 143.9 122.3

Total Proved (Mbbl) 341.7 290.4 Total Probable (Mbbl) 1,350.3 1,147.9

Total Proved and Probable 1,692.0 1,438

Table 11 TXS Proven + Probable Reserves Before Tax Cash Flow NPV

Member Category 0.00% 5.00% 10.00% 15.00% 20.00%

TXS

Proved Dev 6,261 4,920 3,999 3,336 2,840 Proved UnDev. 4,515 3,597 2,895 2,390 2,012

Probable 43,232 33,280 26,469 21,901 17,990 TOTAL P+P 54,008 41,797 33,363 27,626 22,842

The remaining value and production in the model is associated with Contingent Resources and is summarized in the following Tables.


Table 12 Contingent Resource (Development Pending/On Hold) Tight Oil Summary (MBBL)

WI (MBBL) Net WI (MBBL) TXS Contingent

(Development Pending) 12,106 10,290

Sinbad Contingent (Development On Hold) 9,655 8,207

Torrey A Contingent (Development On Hold) 1,664 1,414

Torrey B Contingent (Development On Hold) 1,664 1,414

Total Contingent 25,089 21,325

Table 13 Moenkopi Contingent Resource NPV (On BT Cash Flow)

Before Tax Cash Flow NPV ($M) Member Category 0.00% 5.00% 10.00% 15.00% 20.00%

TXS Contingent 405,900 303,500 234,700 186,500 151,300 Sinbad Contingent 324,400 240,600 184,700 145,700 117,500

Torrey B Contingent 52,257 37,089 27,065 20,195 15,340 Torrey A Contingent 52,090 36,962 26,968 20,123 15,288

Total Contingent 834,647 618,151 473,433 372,518 299,428

Table 14 Land Analysis for Proven and Probable Additional Land Interests

Fortem Group Gross WI To Be Acquired SECTIONS Gross Acres Acres Mbbl Mbbl Mbbl

Section 07 Range11E Township 15 640 150 768.7 135.1 633.6 Section 12 Range 10E Township 15 640 200 768.7 180.2 588.5 Section 13 Range 10E Township 15 640 444 768.7 400 368.7 Section 17 Range11E Township 15 640 90 768.7 81 687.7 Section 19 Range11E Township 15 640 450 768.7 405.3 363.4 Section 20 Range 11E Township 15 640 165 768.7 148.7 620 Section 18 Range 11E Township 15 640 380 767.4 341.7 425.7 Total Proved + Probable Acreage 4,480 1,879 5,380 1,692 3,688

Table 15 Total Future Net Revenue Reserves

Reserve Category Revenue Royalties Op. Costs Aband.

Costs Net Op. Income Capital Costs Before Tax

Cash Flow MM$US MM$US MM$US MM$US MM$US MM$US MM$US

TXS PDP 12.0 1.8 3.0 0.02 6.8 0.58 6.26 TXS Proven

UnDev 8.7 1.3 2.2 0.03 5.2 0.6 4.6

TXS Probable 83.0 12.4 20.5 0.38 49.6 8.0 41.6 Total TXS

P+P+P 93.7 15.5 25.7 0.43 61.6 9.18 52.46

Table 16 Total Future Net Revenue Resources

Resource Revenue Royalties Op. Costs Aband. Costs Net Op. Capital Costs Before Tax


Category Income Cash Flow MM$US MM$US MM$US MM$US MM$US MM$US MM$US

Sinbad Contingent

Dev. On Hold 615.3 92.3 151.7 2.37 369.0 44.6 324.4

TXS Contingent Dev. Pending 765.7 114.9 187.1 2.92 460.8 54.9 405.9

Torrey A Cont. Dev. On Hold 108.0 16.2 24.0 0.83 67.0 14.7 52.3

Torrey B Cont. Dev. On Hold 108.0 16.2 24.2 0.83 66.8 14.7 52.1

Total Cont. 1597 239.6 387.0 6.95 963.6 128.9 834.7

An estimate of risked net present value of future net revenue of Contingent Resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development and chance of discovery to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.

GEOLOGICAL REVIEW:

Introduction The Fortem Resources Lands include a well drilled in 2013 called Wellington Flats 15-11 that discovered oil producible at commercial rates from the locally named unit, the TXS Sandstone of the Black Dragon Member of the Moenkopi Formation. The TXS Sandstone is also productive in the Grassy Trails Field nearby and can be mapped from well log characteristics over a large area. There is relatively sparse well control to map the trend and therefore an element of risk due to local variability in the unit but a thick sand trend can be mapped as illustrated herin in figure. Therefore, the TXS Sandstone on the mapped trend should be considered “Discovered”. Proven and Probable Reserves were assigned to the TXS Unit of the Black Dragon Member and Contingent Resources Unclarified were assigned to Fortem Lands where the TXS was mapped to have greater than 16 feet of net pay. The TXS sandstone has low porosity and permeability and is best considered to be an Unconventional Reservoir and will require horizontal drilling and artificial fracturing to commercially complete wells.

Additional production is potential in other Members of the Moenkopi Formation as evidenced by production from the Grassy Trails Field in Township 16S Range 12E. There is no completion or production from the Sinbad, Torrey “B” or Torrey “A” on Fortem Resources Lands; however these Members produce in the nearby Grassy Trails Field. These units are mapped and cover large areas and much of the Fortem Resources Lands, therefore a Contingent Resource – Unclarified was assigned where these Members, in sufficient thickness, underlie Fortem Resources Lands.


Location The Fortem Resources Lands are located in the Uinta Basin in Utah approximately 5 miles (8 kilometers) southwest of City of Price, Carbon County Utah. The Fortem Lands are situated at the southern edge of the Uinta Basin on a geological feature referrred to as the San Rafael Swell which is a large dome to the south where the Moenkopi Formation outcrops. There are several natural gas pipelines in the area and a well developed road system and easy surface access to all the Fortem lands.

Figure 2 Location of Fortem Resources Lands in Utah

Figure 3 TXS Net Pay Overlaid by Fortem Resources Land (left), Sinbad Net Pay Overlaid by Fortem Resources Land.


Figure 4 Torrey A Net Pay Map overlaid by Fortem Resources land leases (left), Torrey B Net Pay Map overlaid by Fortem Resources land leases (right)

Figure 5 Location of the Fortem Resources Lands in the Uinta Basin

Previous Work The lands were acquired by Black Dragon Energy on January 1, 2016 and Fortem signed a Farmin Agreement in August of 2017.

The Moenkopi Members were originally developed by Whiting Petroleum Corp. in 2010 to 2011. Whiting drilled Wellington Flats 15-11 in 2013 and the well has sporadically produced ~14,000 Barrels of Oil and 91 Mmcf of gas with 6588 barrels of water production. The oil is parrafinitic which has contributed to fairly low production rates and the steep decline rate.


A second well Wellington Flats 19D-2002 vertical pilot hole was drilled in December of 2014 by Whiting Petroleum. The plan was to drill a vertical pilot hole first and then drill a two mile lateral in the TXS Sandstone Member in section 19 and 20 Township 15 Range 11. The lateral well was never drilled and the vertical pilot hole sits temporarily abandoned awaiting completion.

A 3D seismic survey called the Miller Creek 3D survey exists over a portion of the lands and will be reviewed in the future by Fortem.

Figure 6 Regional Structural Framework 2D seismic

Uinta Basin Stratigraphy The 60,000 km2 Uinta Basin is situated in northeastern Utah and was formed during the Laramide Orogeny from Paleocene to Eocene time at time in years of approximately 66 to 34 Million Years ago (Hintze and Kowallis). It is a compressional downwarp basin that incorporates earlier Cretaceous Jurassic and Triassic sediments including the Moenkopi Formation. The San Rafael Swell to the south of the Fortem lands is a large domal feature also formed during the Laramide Orogeny. The north flank of this structure plunges beneath the Fortem lands and is the dominant structural feature. The Moenkopi outcrops on the top of the San Rafael Swell and exhibits oil staining in outcrop there. Deep wells in the Uinta Basin to the north show there is at least a 9000 foot oil column in the Moenkopi.


The Moenkopi Formation, in Utah, represents the mainly marine portion of the Lower Triassic as opposed to the Chinle Formation which consists entirely of continental sediment in the Upper part of the Triassic. Triassic time was a period when all the continents of the world were attached in a super continent called Pangaea. The Triassic is characterized by the red colour of its sediments possibly due to climatic change caused by the immense deserts that were present and the lack of plant life causing lower oxygen levels.

The four members of the Moenkopi of economic interest are from the bottom to the top the TXS unit of the Black Dragon Member, the Sinbad Member and the two units of the Torrey Member the “B” and the “A” which represent two transgressive regressive cycles in the Torrey Member. The TXS is a calcareous sandstone. The Sinbad Member is a carbonate tongue which was deposited during a major marine transgression and the productive Torrey members were laid down in shallow shelf environments and are described as silty dolomites.

Figure 7 Stratigraphic Column of the Moenkopi Formation


Black Dragon Member of Moenkopi Formation

In outcrop the Black Dragon member of the Moenkopi is described on the Utah Geological Survey map as “mostly green-gray or yellow-gray (due to hydrocarbon alteration), dark-red-brown where not altered, thin- to medium-bedded siltstone, fine-grained sandstone, and mudstone; forms a steep slope beneath the Sinbad Limestone Member; local chert-pebble conglomerate at the base; locally dark-gray due to hydrocarbon saturation; 20 to 60 meters (65-200 ft.) thick.” The Black Dragon includes the TXS sandstone which is primary target in the two Wellington Flats wells. The TXS Sandstone is considered to be an estuarine valley fill deposit and therefore has variable reservoir quality.

Sinbad Limestone Member of Moenkopi Formation

On the Utah Geological Survey map the Sinbad is described as a “Medium- and pale-gray to pale-yellow-gray limestone and calcareous sandstone with a few thin shaly siltstone partings; thin to medium bedded; resistant ledge and bench former; generally contains fine-grained sand-sized fossil particles and bivalve casts; locally stylolitic and oolitic; weathers hackly; locally petroliferous; shallow-marine to tidal-flat deposit; 0 to 45 meters (0-150 ft.) thick; thins eastward; forms broad bench throughout much of San Rafael Swell, and is exposed in Labyrinth Canyon just south of quadrangle.”

Torrey Member of Moenkopi Formation Similarly, the Torrey Member is described in outcrop as “Green-gray and yellow-gray, locally red-brown, locally banded yellow-gray and red-brown, thin- to medium-bedded, shaly siltstone and very fine grained sandstone; forms alternating slopes and cliffy ledges; slopes are generally earthy weathering and ledges are platy and slabby weathering; beds are commonly ripple marked; locally petroliferous; 90 to 130 meters (300-420 ft.) thick.”

Uinta Basin Structural Setting Hydrocarbon trap styles in the south Uinta Basin result from stratigraphic structural inter relationships that were formed during the Laramide Paleocene to Eocene aged structures. The Uinta Basin is bounded to the north by the Uinta Mountains and the south by the San Rafael Swell and the Uncompahgre Uplift. The Uinta Basin is separated from the Piceance Basin to the east in Colorado by the Douglas Creek Arch.

The dominant structural feature in the vicinity of the Fortem lands is the San Rafael which appears at the surface as an oval shaped anticline and in the subsurface as a northward plunging structural nose. The San Rafael Swell was formed during the Laramide orogeny when the east west forces ruptured the granitic basement underlying the younger sedimentary rocks causing a large block to uplift.

The target Members of the Moenkopi Formation outcrop over and around the San Rafael Swell and often exhibit hydrocarbon staining at the surface. The deepest recorded hydrocarbon shows are approximately 9,000 feet deep to the north suggesting a thick oil column in the Moenkopi over much of the northern part of the San Rafael structure.


Figure 8 Main Oil and Gas Basins in Utah and Western Colorado

Locally within the Fortem area of interest there is an extensive network of open fractures oriented approximately north south associated with Laramide faulting. These fractures enhance and form a secondary porosity system for the entrapment of hydrocarbons.


Structural Style at the Fortem Resources Lands

Figure 9 The dominant structure in the Fortem lands is the plunging nose of the San Rafael Swell


Figure 10 Fortem Resources area of exploration

Reservoir Geology Most Uinta Basin reservoir rocks are near Jurassic to early Cretaceous in age. The Moenkopi Group was deposited in a predominately marine environment during the Triassic period. The base of the group was deposited in a shallow marine environment, made apparent by the mostly fine grained nature of the shale deposit along with the interbedded sandstone. The formation then transgresses to show thick beds predominated by limestone and dolostone. This was followed by a series of transgressive and regressive sequences, as the deposits represent a high-energy sabkha environment with the presence of primary dolomite and anhydrites.

TXS Sand The TXS sand is represented by coarse grained sand interbedded with shaly siltstones, as denoted by the Wellington Flats 15-11-18E well. In addition to the sediments, the presence of the trace fossil “Thalassinoides” which is a common marine trace fossil would indicate that the TXS sand was deposited in shallow marine environment, with channel influence such as that found in an estuarine system. The estuarine sediments are coarse grained and display thick-bedded crossbedding and contains calcareous cement. Porosity in the TXS sand may be higher than that of the other 3 members of the Moenkopi as a result of dissolution of the calcareous cement, resulting in secondary porosity.

Sinbad Dolomite The Sinbad member primarily consists of carbonates with the presence of oolitic grainstone and fossiliferous wackestone. These oolitic grainstones were deposited during a marine transgression along a high energy shoreline. Dolomitization of the ooids has resulted in intraparticle porosity, which is still relatively high despite the quartz and calcite cementation seen in the Grassy Trail Field.

Torrey A & B Sandstones


The Torrey A & B members of the Moenkopi group are deposited on a shallow shelf in an intertidal environment. These deposits consist of thinly bedded silty sandstones, interbedded with layers of primary dolomite and anhydrite. The result of a low water table allows for the highly concentrated pore waters to be easily evaporated, thus increasing the quantity of dolomite and anhydrites found in the reservoir, resulting in a sabkha type environment. The porosity of the Torrey A & B is considered poor as the result of the pores being cemented by the resulting anhydrite.

Oil Generation and Migration

Source The principal source rock for the Fortem Resources Lands is probably the Moenkopi section itself. The entire section is oil saturated over a 9000 foot interval from the outcrop on top of the San Rafael swell to a depth of 9000 feet. (Mitchell 1985). Oil seeps from the Triassic Moenkopi Formation are found at surface outcrop throughout the San Rafael Swell indicating an active petroleum system.

Other possiblilities for source rocks include the Park City Phosphoria Formation of Permian age immediately beneath the Moenkopi (Sprinkell 1994) and various units within the Pennsylvanian Paradox formation and Mississippian Manning Canyon/Doughnut shale and Delle phosphatic unit.

The Fortem properties are located on the northern side of the San Rafael and overly a sequence of Permian, Pennsylvanian and Mississippian that are productive in the Paradox Basin to the southeast.

Migration The principal reservoirs are in contact with main source rock; therefore migration would have been directly into the reservoirs.

Alternatively the 3D seismic demonstrates a complicated sets of faulting and fracturing beginning with Pre Pennsylvanian orogenies and the formation of the Uncompahgre Uplift and the Emery high. It is possible oil generated in the older rock could have migrated vertically into the Moenkopi members.

Seal Principal seal for the Moenkopi reservoirs are within the Moenkopi itself which is largely a sand, shale, carbonate sequence with abundant shale interbeds.

Petroleum Potential of the Fortem Resources Lands Permit The Company has Proven Non Producing, Proven Undeveloped and Probable Reserves in the TXS Member of the Moenkopi, in addition to a large Contingent Resource in the TXS, the Sinbad and the Torrey A and B. The Reserves and Resources are considered to be Discovered Unconventional Tight Oil. They are Unconventional in the sense that horizontal wells and


artificial fracturing will be required to develop the Reserves and Resources and all the Members of the Moenkopi have low porosity and permeability.

The Contingent Resources were further sub-classified according to NI 51-101 definitions according to the Chance of Development into Contingent Resources Development Pending in the case of the TXS sandstone and Contingent Resources Development on Hold for the Resources in the Sinbad, Torrey A and B.

Proven Reserves Proven Reserves were assigned to the TXS Sandstone in Section 18 Township 15 Range 11 to those lands within the section that Fortem has an interest. The Reserves were calculated on a Gross basis assuming a 100% working interest then multiplied by the Fortem net working interest and deducting the encumbrances. On average in this area the Fortem interest is approximately 65.63% net revenue interest.

The Wellington Flats 15-11-18E well was drilled and is completed in the northern half of section 18 and was completed and has produced some oil from the TXS Sandstone. The well has a 3,250 foot lateral into the interval of which approximately 785 feet is in pay. The well bore left the zone twice, as seen on the interpretation in Figure below. The lateral was cased with 4 ½ inch casing that was cemented in place and it was hydraulically fracture stimulated with a slick water frac in several intervals.


Figure 11 Wellington Flats 15-11-18E Vertical Section displaying directional survey

The well logs run on the Wellington Flats 15-11-18E vertical pilot hole show a 32 foot pay interval in the TXS Sandstone. This interval was cored along with the rest of the Moenkopi by Whiting Petroleum. The cored showed matrix porosities varying between 4% and 11% similar to


those exhibited in the well log.

Figure 12 Gamma Ray Neutron Density log TXS Sandstone - Wellington Flats 15-11 18E

One half the section was considered Proven Non-Producing by virtue of the presence of the well and the production there from. The other half of section 18 is considered to be Proven Undeveloped. The reserves were calculated on the whole section where Fortem is determined to have an interest and then divided by two into the two categories.

The parameters used to calculate the Proven Reserves were determined from well logs and core data.


Table 17 Fortem Resources Lands Permit Proven Reserves (Volumetric)

TXS Sandstone

Proven Reserves (Barrels) Probable Reserves

(Barrels)

Proven Non-Producing

Proven Undeveloped

Gross Group (100% WI) 210,464 210,464 2,218,855 Fortem WI (75% ) 157,848 157,848 1,664,141

Table 18 Parameters to Determine Proven Reserves

TXS Sandstone Gross (100% WI) Proven non Producing and Proven Undeveloped Reserves

Twp. Rage Sec Area H ϴ So Boi PIIP Rf (%)

Proven Reserves Production

Remaining Proven

Reserves 15 11 18 60 32 7% 82% 1.1 777,267 10.0 77,727 64,322 15 11 18 160 30 7% 82% 1.1 1,943,167 10.0 194,317 13,405 180,912 15 11 18 90 28 7% 82% 1.1 1,020,163 10.0 102,016 102,016 15 11 18 70 26 7% 82% 1.1 736,784 10.0 73,678 73,678

380 4,477,381 447,738 420,928

Production 13,405 bbls


Contingent Resources Development Pending

TXS Sandstone

Tight Oil Contingent Resource Development Pending Risk Factors Risk factors were calculated based on the Best Estimate using factors defined below. The abbreviation “CODev” stands for “Chance of Development (C.O. Dev). In the Table, that is included within the Reservoir Column and is shown as “Chance of Reservoir multiplied by C.O. Dev.” C.O.Dev. is the chance that the project will be developed. There is nothing to impede development of the Contingent Resources. There is no political risk, there is transportation infrastructure nearby, and surface facilities will have to be built. The TXS Sandstone will require horizontal drilling and artificial fracturing to develop the Resources and is by definition a Tight Oil play. Additional wells will be required before the Resources can be reclassified as Reserves.

TXS Sandstone The TXS Sandstone seems to fall in the middle ground of Conventional and Unconventional Resources where horizontal wells with artificial fracturing will be required to develop the trend of favourable sand thickness. There is reservoir risk in that the sand is not a “sheet” sand and therefore there is risk attached to future drilling. The play as described above is on an estuarine trend defined by sparse well control outside of the Grassy Trails Field. However there is predictability as demonstrated by the success of the Wellington Flats 15-11-18E well. The net pay thins considerably in the Grassy Trails Field area possibly because this area is a lower energy depositional environment at the head of the estuary confining the TXS sand body. There is likely to be heterogeneity along the trend with respect to cementation and clay content. The sandstone has low porosity and low permeability mainly due to the extensive calcite cementation that would have developed early in the sandstone’s diagenetic history and reduced the storage capacity of the reservoir. Additional fracture porosity cannot be defined with the data reviewed but is possibly visible on the seismic data in the area. This seismic data has not yet been reviewed by Fortem. Because the entire section is oil saturated there is little risk attached to the normal factors considered in determining geological risk such as source, timing of migration, seal and trap, but there is some risk that the reservoir porosity and permeability may vary from location to location. In addition the faulting present in the Grassy Trails Field seems to isolate some fault blocks suggesting the faults are sealing or partially sealing the migration of oil.

The unconventional risk factors also do not apply in the TXS Sandstone, such as total organic carbon, thermal maturity and propensity of the formation to fracture are also clearly favourable in the entire Moenkopi section.

The term used in the Resource Definitions is Chance of Development (“COD”). Since the TXS Contingent Resource is already “Discovered” we feel a COD risk factor of 66% should be applied to additional delineation and Development wells. This factor could be increased with an additional technical review of the seismic data. Six different parameters were considered and these are in no particular order: drilling, completion pricing, market, decline and funding.


Table 19 Chance of Development Risk Parameters

Chance of Development Risk Parameters Prospect: TXS Sandstone Drilling

Probability Value Completion Probability Value Pricing

Probability Value Market Probability Value Decline

Probability Value Funding Probability Value

0% 0.92 5% 0.80 20% 1.00 20% 1.00 5% 0.55 20% 1.00 10% 0.94 10% 0.85 20% 1.00 20% 1.00 20% 0.60 20% 1.00 20% 0.96 63% 0.90 20% 1.00 20% 1.00 50% 0.66 20% 1.00 65% 0.98 20% 0.95 20% 1.00 20% 1.00 20% 0.70 20% 1.00 5% 1.00 2% 1.00 20% 1.00 20% 1.00 5% 0.75 20% 1.00

The principal risk in the TXS Sandstone is the decline and ultimate recovery from the TXS reservoir as there is limited production history and the well was not completed in an optimal way. When run through a Monte Carlo simulation the Best Estimate was 65.8% Chance of Development.

Table 20 TXS Sandstone Chance of Development

TXS Sandstone C.oD. Low Estimate 0.596 Best Estimate 0.658 High Estimate 0.726

Table 21 Moenkopi Contingent Resource Development Pending

Fortem working Interest: 75.00%


Fortem Net Risked

Contingent Resource

Development Pending

Moenkopi Contingent Development On Hold Resources Unrisked

C.O.Dev Risked

Contingent Resources


Tight Oil Resources- Development Pending

Member Low

Estimate (1C)

Best Estimate

(2C)

High Estimate

(3C)

Low Estimate

(1C)

Best Estimate

(2C)

High Estimate

(3C)

Best Estimate

(2C)

Best Estimate

(2C)

Best Estimate

(2C)

TXS Sandstone 70.0 114.7 188.0 10.1 20.7 40.2 66% 13.6 10.2

70.0 114.7 188.0 10.1 20.7 40.2 13.6 10.2

Contingent Resources Development on Hold

Sinbad Dolomite


The Sinbad Dolomite carbonate is considered to be an Unconventional Tight Oil reservoir covering a much larger area than the TXS Sandstone. However its reservoir distribution is poorly understood and the relationship of fractures to production is also not known outside of the Grassy Trails Field, therefore a Chance of Development Risk Factor of 57% is used for the Sinbad.

Approximately 30,000 gross acres and 19,733 net to Fortem acres were tabulated as having Contingent Resources (Development on Hold) pay where the porosity was greater than 3% and the net pay thickness was greater than 16 feet. Eighteen sections of this were considered to have a Contingent Resource (Development on Hold) in the Sinbad, where these section overlay the TXS sand trend as these sections were the most likely to be developed in the future.

Table 22 Chance of Development Risk Parameters

The Sinbad was mapped by well control and evaluation of older wireline logs, hence a portion is considered to be Discovered. Fracture density and location outside of the area covered by the Miller Creek 3D seismic survey is uncertain, therefore the Sinbad future development status is at present uncertain. A ”Development on Hold” classification was assigned because additional seismic and testing will be required before the Resource Classification can be upgraded.

Table 23 Sinbad Dolomite Chance of Development

Sinbad C. of D.

Low Estimate 0.513

Best Estimate 0.571

High Estimate 0.636

The Torrey “A” and “B” The Torrey “A” and “B” were deposited in similar depositional environments and therefore should have similar risk factors. The Torrey Members have the additional reservoir risk of anhydrite cement primary dolomite matrix. Therefore natural fracturing is essential to form reservoirs in these units. A Best Estimate Chance of Development risk of 38% and 34% respectively is applied to these Members. Approximately six sections are considered to be Contingent Resources, the balance of the lands are prospective where the calculated net pay on well logs is greater than 10 feet in either unit.

Chance of Development Input Parameters Prospect:

Drilling Completion Pricing Market Decline FundingProbability Value Probability Value Probability Value Probability Value Probability Value Probability Value

0% 0.92 5% 0.8 20% 1 20% 1.00 5% 0.55 20% 1.0010% 0.94 10% 0.85 20% 1 20% 1.00 20% 0.6 20% 1.0020% 0.96 63% 0.9 20% 1 20% 1.00 50% 0.66 20% 1.0065% 0.98 20% 0.95 20% 1 20% 1.00 20% 0.7 20% 1.00

5% 1 2% 1 20% 1 20% 1.00 5% 0.75 20% 1.00100% 100% 100% 100% 100% 100%

Sinbad

Comment [MK1]: How was this determined?


Table 24 Torrey B Chance of Development Risk Parameters

Table 25 Torrey B Chance of Development

Torrey B C. of D.

Low Estimate 0.327

Best Estimate 0.384

High Estimate 0.451

Table 26 Torrey A Chance of Development Risk Parameters

Table 27 Sinbad Dolomite Chance of Development

Torrey A C. of D.

Low Estimate 0.288

Best Estimate 0.337

High Estimate 0.394

Prospect:

Drilling Completion Pricing Market Decline FundingProbability Value Probability Value Probability Value Probability Value ProbabilityValue Probability Value

0% 0.92 5% 0.7 20% 1 20% 1.00 5% 0.35 20% 1.0010% 0.94 10% 0.75 20% 1 20% 1.00 20% 0.45 20% 1.0020% 0.96 63% 0.8 20% 1 20% 1.00 50% 0.5 20% 1.0065% 0.98 20% 0.85 20% 1 20% 1.00 20% 0.55 20% 1.00

5% 1 2% 0.9 20% 1 20% 1.00 5% 0.6 20% 1.00100% 100% 100% 100% 100% 100%

Torrey BChance of Development Input Parameters

Prospect:

Drilling Completion Pricing Market Decline FundingProbability Value Probability Value Probability Value Probability Value ProbabilityValue Probability Value

0% 0.92 5% 0.6 20% 1 20% 1.00 5% 0.35 20% 1.0010% 0.94 10% 0.65 20% 1 20% 1.00 20% 0.45 20% 1.0020% 0.96 63% 0.7 20% 1 20% 1.00 50% 0.5 20% 1.0065% 0.98 20% 0.75 20% 1 20% 1.00 20% 0.55 20% 1.00

5% 1 2% 0.8 20% 1 20% 1.00 5% 0.6 20% 1.00100% 100% 100% 100% 100% 100%

Torrey AChance of Development Input Parameters


Table 28 Moenkopi Contingent Resource Development on Hold



Fortem Net Risked

Contingent Resource

Development on Hold

Moenkopi Contingent Development On Hold Resources Unrisked

C.O.Dev Risked

Contingent Resources


Tight Oil Resources- Development on Hold

Member Low

Estimate (1C)

Best Estimate

(2C)

High Estimate

(3C)

Low Estimate

(1C)

Best Estimate

(2C)

High Estimate

(3C)

Best Estimate

(2C)

Best Estimate

(2C)

Best Estimate

(2C)

Sinbad 40.1 59.3 87.8 6.2 9.7 15.2 57.1% 5.5 4.2

Torrey B 8.5 14.7 25.5 0.9 1.7 3.1 38.4% 0.6 0.5

Torrey A 8.5 14.8 25.6 0.9 1.7 3.2 33.7% 0.6 0.4

Total 57.1 88.8 138.9 1.8 13.1 21.5 6.8 5.1

In the determination of prospective natural gas resources stated in the Tables above, Monte Carlo simulation incorporating 1000 iterations of the variables, area, pay thickness porosity, water saturation and formation volume factor (Boi). The advantages of the Monte Carlo simulation over the deterministic method (single point estimate), are;

1. Multiple probability outcome distributions are generated, like Normal, LogNormal, Uniform, Triangular, Pert and finally Discrete distributions. Of these distributions, the Lognormal distribution is the most commonly used in determining oil and gas reserves. This is primarily due to the complexity in the number of variables used in reserve calculation. Values used in this type of distribution are positively skewed (i.e. variables are all positive and do not go below zero), the result of this is that the distribution curve, representing the iteration calculations is not symmetric as one would get in a ‘Normal Distribution Curve’.

2. Monte Carlo provides a greater sensitivity analysis as opposed to the Deterministic analysis which provides only a single point estimate

3. Using Deterministic analysis makes it difficult to model the effects of different combinations of variables on the calculations. Further, Monte Carlo Simulation analysis has the greatest impact on the outcome. In the case of the Fortem Resources Lands analysis, the factors which had the greatest impact were areal extent, and pay thickness.


Prospective Resources The Sinbad, the Torrey B and Torrey A Prospective Resources Undiscovered Petroleum Initially in Place and the Prospective Resources, are on the lands net to Fortem outside of the Contingent Resources areas. The areas and net pays are based upon well control but sine there is no existing production and the Prospective Resources lands are at a significant distance to the Grassy Trails Field, these areas are considered to be undiscovered. To risk theses Prospective Resources a Chance of Development, the same as determined for the Contingent Resources, and a Chance of Discovery are applied to the respective Members of the Moenkopi Formation.

Sinbad Dolomite The Sinbad, was considered to have Prospective Resources on lands having greater than 16 feet of net pay. The principal risks are same as for the Chance of Developemnt for the Contingent Resources above and reservoir in the calculation of the Chance of Discovery.

Table 29 Sinbad Chance of Discovery Risk Parameters

Table 30 Sinbad Dolomite Chance of Discovery

Sinbad C. of Discovery

Low Estimate 0.193

Best Estimate 0.287

High Estimate 0.426

The Torrey “A” and “B” Both the Torrey Members have as higher reservoir risk and consequently a lower Chance of Discovery.

Table 31 Torrey A Chance of Discovery Risk Parameters

Chance of Discovery Input Parameters Prospect:Prospective Resources

Source Migration Reservoir Seal TrapProbability Value Probability Value Probability Value Probability Value Probability Value

20% 0.97 20% 0.75 20% 0.3 20% 0.97 20% 0.7520% 0.97 20% 0.8 20% 0.4 20% 0.97 20% 0.7520% 0.98 20% 0.85 20% 0.5 20% 0.97 20% 0.7520% 0.98 20% 0.9 20% 0.6 20% 0.96 20% 0.820% 0.98 20% 0.95 20% 0.7 20% 0.96 20% 0.7

Sinbad


Table 32 Torrey A Chance of Discovery

Torrey A C. of Discovery

Low Estimate 0.073

Best Estimate 0.153

High Estimate 0.321

Table 33 Torrey B Chance of Discovery Risk Parameters

Table 34 Torrey B Chance of Discovery

Torrey B C. of Discovery

Low Estimate 0.071

Best Estimate 0.152

High Estimate 0.325



20% 0.97 20% 0.75 20% 0.1 20% 0.97 20% 0.7520% 0.97 20% 0.8 20% 0.2 20% 0.97 20% 0.7520% 0.98 20% 0.85 20% 0.3 20% 0.97 20% 0.7520% 0.98 20% 0.9 20% 0.4 20% 0.96 20% 0.820% 0.98 20% 0.95 20% 0.5 20% 0.96 20% 0.7

100% 100% 100% 100% 100%

Torrey A



20% 0.97 20% 0.75 20% 0.1 20% 0.97 20% 0.7520% 0.97 20% 0.8 20% 0.2 20% 0.97 20% 0.7520% 0.98 20% 0.85 20% 0.3 20% 0.97 20% 0.7520% 0.98 20% 0.9 20% 0.4 20% 0.96 20% 0.820% 0.98 20% 0.95 20% 0.5 20% 0.96 20% 0.7

100% 100% 100% 100% 100%

Torrey B


Table 35 Moenkopi Contingent Resource Development on Hold



Fortem Net Risked

Prospective Resource

Moenkopi Prospective Resources Unrisked

C.O.Dev C.O. Discovery

Risked Prospective Resources Undiscovered PIIP Prospective Unconventional

Tight Oil Resources

Member Low

Estimate (1C)

Best Estimate

(2C)

High Estimate

(3C)

Low Estimate

(1C)

Best Estimate

(2C)

High Estimate

(3C)

Best Estimate

(2C)

Best Estimate

(2C)

Best Estimate

(2C)

Best Estimate

(2C)

Sinbad 47.0 86.0 154.5 7.9 14.3 25.7 57.1% 28.7% 2.3 1.8

Torrey B 80.4 146.3 146.3 9.0 17.0 32.2 38.4% 15.2% 1.0 0.7

Torrey A 95.5 187.2 367.5 10.1 21.3 43.8 33.7% 15.3% 1.1 0.8

Total 222.9 419.5 668.3 27.0 52.6 101.7 4.4 3.3

DEFINITIONS OF RESERVES, CONTINGENT AND PROSPECTIVE RESOURCES, AND METHODOLOGY

In the Fortem Resources Lands there are currently none producing Reserves. There are Contingent Resources and Prospective Resources in the exploration prospects identified by seismic and geological information. Approximately 1.817 Bcf of gas was produced from a perforated interval in Wellington Flats 15-11. This Past Production was deducted from the Contingent Recoverable Resource recorded in Tables 2.

Table 36 Resources Classification Framework


Total Petroleum Initially in Place (“PIIP”) refers to the total quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes the petroleum that exists in known accumulations prior to production and the estimated quantities yet to be discovered in the various leads and prospects identified by seismic and inferred by geology. A portion of the PIIP will be recoverable as determined by ultimate recovery factors and the estimated recoverable portion is further classified as Reserves, Contingent Resources or Prospective Resources. Discovered Petroleum Initially in Place (“Discovered PIIP”) is the total quantity of Petroleum that is estimated as of the effective date of the Report to be contained in known accumulations prior to production. Past Production is the cumulative quantity of Petroleum that has been recovered as of the effective date of the Report. It is the sum of all raw production which includes sales and non-sales product quantities as measured and reported by the operators. It is not included in any values given the reserves, contingent resources or prospective resources, having already been produced and sold. Future production is sub-classified as reserves, contingent resources or prospective resources.

Multiple development projects may be applied to each known accumulation which may be separated vertically into different formations or by area in different pools; each project will recover a portion of the PIIP according to its unique reservoir characteristics. The projects will be subdivided

Resources Classification Framework: The Range of Uncertainty reflects the range of estimated quantities potentially recoverable from an accumulation by project, and is determined by probabilistic means. The vertical axis represents the Chance of Commerciality, the chance that a project will be developed and reach commercial producing status and is a subjective determination based on various commercial, engineering and geological risk factors.


into Commercial and Sub-Commercial at the effective date with the estimated recoverable petroleum quantities being classified as Reserves and Contingent Resources. Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from the effective date under defined conditions. Reserves must be discovered, recoverable, commercial, and remaining as of the effective date based on the development projects applied. Reserves are further categorized into Proven, Probable and Possible according to the level of certainty associated with the estimates, and may be sub-classified based upon production status and project maturity.

Reserves are classified according to the degree of certainty associated with the estimates. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be commercially recoverable from known accumulations, from a given date forward, based on

• analysis of drilling, geological, geophysical, and engineering data; • the use of established technology; • and economic conditions, which are generally accepted as being reasonable, and

shall be disclosed.

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 + probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved + probable + possible reserves. Resources are defined in the Canadian Oil and Gas Evaluation Handbook (COGEH) Volume 1, section 5 as follows: Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations , but the applied projects are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality.

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 sub classified based on project maturity and/or characterized by their economic status.

Not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on the forecast of fiscal conditions over the life of the project.


For Contingent Resources, the risk component relating to the likelihood that an accumulation will be commercially developed is referred to as the “chance of development.” For contingent resources, the chance of commerciality is equal to the chance of development.

In 2015 further amendments to the COGEH have included Project Maturity Sub-classes, definitions as follows:

Table 37 Resources Classification Framework with Project Maturity Sub-classes

Development Pending are contingencies that are being actively pursued; expect resolution in a reasonable time period; are directly influenced by the developer with both, internal approvals and commitment and development timing and; have a high chance of development (>80%).

Development On Hold are contingencies with major non-technical contingencies identified; have a reasonable chance of development (>50%); have contingencies that are beyond the control of the developer including but not limited to: external approvals, economic factors, market access, political factors and social license.

Development Unclarified are contingencies that have not been clearly defined; the project is currently under active evaluation; significant further appraisal may be required; progress is expected in a reasonable time period; chance of development is difficult to assess and could be a big range (20%-80%).

Development Not Viable are contingencies that have been identified; the project was evaluated and considered not viable or significant further appraisal may be required; progress is not expected in a reasonable time period and; has a low chance of development (<<50%).

Contingent Resources -Development Pending and -Development On Hold are considered economic, Contingent Resources -Development Unclarified have economics that are


undetermined, and Contingent Resources –Development Not Viable are considered sub-economic.

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub classified based on project maturity.

Not all exploration projects will result in discoveries. The chance that an exploration project will result in the discovery of petroleum is referred to as the “chance of discovery.” Thus, for an undiscovered accumulation, the chance of commerciality is the product of two risk components — the chance of discovery and the chance of development.

Estimates of resources always involve uncertainty, and the degree of uncertainty can vary widely between accumulations/projects and over the life of a project. Consequently, estimates of resources should generally be quoted as a range according to the level of confidence associated with the estimates. An understanding of statistical concepts and terminology is essential to understanding the confidence associated with resources definitions and categories. These concepts, which apply to all categories of resources, are outlined below. The range of uncertainty of estimated recoverable volumes may be represented by either deterministic scenarios or by a probability distribution. Resources should be 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 (P90) 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 (P50) 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 (P10) that the quantities actually recovered will equal or exceed the high estimate. This approach to describing uncertainty may be applied to reserves, contingent resources, and prospective resources. There may be significant risk that sub commercial and undiscovered accumulations will not achieve commercial production, however, it is useful to consider and identify the range of potentially recoverable quantities independently of such risk.


Unrecoverable petroleum quantity is that portion of the Discovered or Undiscovered PIIP which is estimated at the effective date not to be recoverable by future development. It is that portion of the PIIP remaining after the recoverable Contingent or Prospective Resource is removed. A portion of this petroleum quantity may become recoverable in the future as commercial circumstances or technological improvements occur, but are given no value at the Effective Date. The remaining portion may never be recovered due to physical and chemical restraints in petroleum reservoirs.

Deterministic and Probabilistic Methods Reserves or resource estimates may be prepared using either deterministic or probabilistic methods.

a. Deterministic Method The deterministic approach, which is the one most commonly employed worldwide, involves the selection of a single value for each parameter in the reserves or resources calculation. The discrete value for each parameter is selected based on the estimator’s determination of the value that is most appropriate for the corresponding reserves or resources category.

b. Probabilistic Method Probabilistic analysis involves describing a range of possible values for each unknown parameter. This approach typically consists of employing computer software to perform repetitive calculations (e.g., Monte Carlo simulation) to generate the full range of possible outcomes and their associated probability of occurrence. In the determination of prospective natural gas resources stated in Table 12, above, Monte Carlo simulation incorporating 1000 iterations of the variables, area, pay thickness porosity, water saturation and gas formation factor (Bg). The advantages of the Monte Carlo simulation over the deterministic method (single point estimate), are;

1. Multiple probability outcome distributions are generated, like Normal, LogNormal, Uniform, Triangular, Pert and finally Discrete distributions. Of these distributions, the Lognormal distribution is the most commonly used in determining oil and gas reserves. This is primarily due to the complexity in the number of variables used in reserve calculation. Values used in this type of distribution are positively skewed (i.e. variables are all positive and do not go below zero), the result of this is that the distribution curve, representing the iteration calculations is not symmetric as one would get in a ‘Normal Distribution Curve’.

2. Monte Carlo provides a greater sensitivity analysis as opposed to the Deterministic analysis which provides only a single point estimate.

3. Using Deterministic analysis makes it difficult to model the effects of different combinations of variables on the calculations. Further, Monte Carlo Simulation analysis has the greatest impact on the outcome. In the case of the Fortem Resources Lands analysis, the factors which had the greatest impact were areal extent, and pay thickness.

c. Comparison of Deterministic and Probabilistic Estimates


Deterministic and probabilistic methods are not distinct and separate. A deterministic estimate is a single value within a range of outcomes that could be derived by a probabilistic analysis. There should be no significant difference between reported reserves or resources estimates prepared using deterministic and probabilistic methods.

d. Application of Guidelines to the Probabilistic Method The following guidelines include criteria that provide specific limits to parameters for proved reserves and resources estimates. For example, volumetric estimates are restricted by the lowest known hydrocarbon (LKH). Inclusion of such specific limits may conflict with standard probabilistic procedures which require that input parameters honour the range of potential values. Nonetheless, it is required that the guidelines be met regardless of analysis method. Accordingly, when probabilistic methods are used, constraints on input parameters may be required in certain instances. Alternatively, a deterministic check may be made in such instances to ensure that aggregate estimates prepared using probabilistic methods do not exceed those prepared using a deterministic approach including all appropriate constraints.

The copyright holders of COGEH have given the Alberta Securities Commission and users of NI 51-101 authority to reproduce Section 5 of volume 1 of COGEH. The COGEH itself can be obtained from the Petroleum Society of the Canadian Institute of Mining, Metallurgy and Petroleum, Calgary Chapter at www.petsoc.org. This Report is meant to be a guide to the Company’s Senior Management for strategic planning and review for a reserve and resource evaluation.

In this Report, Probabilistic methodology was used to determine Contingent and Prospective Resources. Resources for each prospective Fortem Resources Inc. were determined by evaluating all parameters and providing low, best and high estimates for each parameter. A triangular distribution was assumed on each parameter and a Monte Carlo simulation was done for resources based upon a random number generator and one thousand calculations. The resulting histogram was analyzed and the P10 (highest estimate), P50 (best estimate) and P90 (lowest estimate) numbers were recorded in the Tables attached. Referring to the Tables, the “Best Estimate” would be the P50 number, the estimate of the 50% probability of a particular unrisked reserve being found. Unrisked Prospective Resources were risked by multiplying the best estimate Chance of Discovery (“COD”) by the unrisked Prospective Resource for each Fortem Resources Inc. yielding the Best Estimate Prospective Resource. COD was calculated by estimating the probability through a triangular distribution of low, best, and high estimates for each of the source and generation of oil, the presence of a trap, the presence and effectiveness of the reservoir, the timing and ability of oil to migrate into the trap, and seal effectiveness.

http://www.petsoc.org/



Glossary 000 thousands Mcf thousand cubic feet $000 thousand dollars Mcf/d thousand cubic feet/day AOF absolute open flow mD millidarcies AOFP absolute open flow potential mKB meters from Kelly Bushing API American Petroleum Institute MM million(s) APO after payout MMBbls million barrels of oil MMbbl/d Bbl barrel(s) MMboe MM barrels of oil equivalent Bbl/d barrels per day MMboe/d MMbbl of oil equivalent/day Bbl/MMcf barrels per million cubic feet Btu British thermal units Bcf billions of cubic feet MMcf million cubic feet BHP bottom hole pressure MMcf/d million cubic feet per day BOE barrels of oil equivalent MMcfe/d MMcf equivalent/day BOE/d barrels of oil equivalent/day MMscf/d MMcf standard per day Bopd barrels of oil per day stb stock tank barrels BPO before payout Btu British thermal unit NCGORR non- convertible gross overriding royalty CBM coal bed methane NGLS natural gas liquids cf cubic foot/feet NPV net present value Cp centipoise CSG coal seam gas OCM oil-cut mud Cum cumulative D&A drilled and abandoned PIIP pet initially in place DST drillstem test E3m3d thousands of cubic meters/day P&NG petroleum and natural gas GIP gas in place PDP proved developed producing

Gj gigajoule(s) reserves GOP gross oil pay Pj petajoule (10/15 joules) GOR gas/oil ratio GORR gross overriding royalty GPP good production practices GTS gas to surface HVP high vapor pressure IP initial production MD measured depth M thousand(s) PNP proved non- producing reserves m3 cubic meter(s) PPM parts per million M$ thousands of dollars PUD proved undeveloped reserves MMbbl thousand barrels of oil or NGLs PSI pounds per square inch Mbbl/d thousand barrels of oil per day Rt Resistivity RLI reserve life index


Mboe thousand barrels of oil equivalent Rw water resistivity Mboe/d thousand barrels of oil equivalent Per day Nappe a complex recumbent fold system SAGD steam-assisted gravity drainage Scf/stb standard cubic feet per standard barrel SP spontaneous potential STPIIP stock tank original oil in place Sw water saturation Tcf trillion cubic feet TD total depth Tmax highest temperature rock has attained TOC total organic carbon TVD true vertical depth WI working interest WTI West Texas Intermediate

Conversion Table - National Energy Board

1.00 M3 = 35.3147 Cubic feet (cf) natural gas (@ 14.73 psia and 60° F) 1.00 Hectare = 2.4711 acres 1.00 Metre= 3.2808 feet


Partial Bibliography

Hintze L.F. and Bart J. Kowallis: 2017, Geologic History of Utah, Brigham Young University Geological Studies Special Publication 9, Provo Utah


APPENDIX 1: Wellington Flats 15-11 Composite Log and Tully 16-9-36D

1 8 3 9

0 38

3 5

9 5

4 7

C C


APPENDIX 2:Wellington Flats 15-11 Production Chart


APPENDIX 3: Fortem Resources Lands-1

Documents

Fortem Resources Inc | A Gas and Oil Company - Attention: … · 2019-05-07 · APEX GLOBAL ENGINEERING INC. Page 2 either the Company’s technical representatives or on behalf of