fossil bay energy - investment opportunity cim - september 2016 - bmm v3

A Revolutionary Method for Enhanced Oil Recovery

Investment Opportunity CIM

October 2016

Table of Contents

Company Overview A

Industry Overview B

Competitive Landscape C

Market Opportunity D

Pilot Project 1: Cigna 1-23 E

Pilot Project 2: State Cleon 2-13 F

Investment Opportunity G

2

Company Overview

3

Introduction: Fossil Bay Energy

Fossil Bay Energy (FBE) is commercializing a novel method of Enhanced Oil Recovery that revitalizes production of depleted oil fields, doubling recoverable crude oil reserves.

The Fossil Bay management team will utilize its contacts within the oil industry to develop strategic relationships with oil producers in Michigan and throughout North America to secure Exhaust Gas EOR development rights on millions of barrels of “Stranded Oil.”

4

75% of the world’s proven oil reserves are stranded underground after conventional extraction is complete.

Currently, the best method for increasing crude oil production after conventional methods is to flood the reservoir with CO2 gas.

The problem is that sources of CO2 are very limited, and the pipeline infrastructure needed to transport CO2 gas makes the method viable only for very large oil reservoirs.

The Fossil Bay process utilizes a mobile gas producing unit, producing exhaust gas directly at the wellhead for Enhanced Oil Recovery. This method makes gas flooding economically viable for thousands of oil fields, effectively capturing hundreds of millions of barrels of stranded crude oil.

Example of oil recovery through primary, secondary, and tertiary methods.

Unique Opportunity as Exclusive Operator

5

During Equipment IP exclusivity with Weatherford International, LTD, Fossil Bay will have control over deal terms and our ability to extract profit from these relationships.

If and when exclusivity expires, Fossil Bay will still be able to operate effectively and will have a head start in terms of knowledge and ability to execute, but FBE will be operating in a more efficient market with the potential for heated competition.

Fossil Bay co-founder and CEO, Dan Kulka, is the author of a granted patent titled ‘Method and system for extraction of liquid hydraulics from subterranean wells,’ which covers the method of using exhaust gas as a source for gas flooding.

The other key IP fence that Fossil Bay Energy can exploit is the exclusive license with Weatherford International. Weatherford controls intellectual property around the equipment from which FBE will benefit.

U.S. & Canada Patent # 6,662,885 describes a method of producing a pressurized stream of substantially inert gas.

The method involves collecting the exhaust gases from an internal combustion engine, directing the exhaust gases into the intake of a compressor for compressing to a desired pressure, and recirculating a portion of the compressed exhaust gases back to the intake of the compressor such that the pressure of the exhaust gases within said compressor intake is maintained above atmospheric pressure.

Also disclosed is an apparatus for producing a pressurized stream of substantially inert gas utilizing the described method.

Management Team

Wm. Cobb and Associates, Petroleum Engineering Adviser

6

Dan Kulka, Co-founder, CEO

Mr. Kulka has 30+ years of experience in the Oil and Gas Industry as an “explorationist” developing prospects in the Michigan, Illinois and Appalachian Basins. From 1997-2000, Mr. Kulka managed an EOR Joint Venture with Shell Oil Noreast, American Natural Resources Pipeline and Gas Storage Companies (ANR), and Forcenergy, Inc. This JV aimed to exploit the depleted Niagaran Reefs of Northern Michigan using Methane gas.

Mike McGhan, Co-founder, COO

Mr. McGhan has 30+ years of experience in gas compression. Mr. McGhan was co-founder and CEO of Hanover Compressor (now “Exterran”) during the 1990s and Valerus Compression Services starting in 2004. Mr. McGhan will oversee Fossil Bay’s manufacturing and exploitation of its first-to-market, patented, portable exhaust gas compression and injection equipment.

Brian Marshall CFO

Mr. Marshall consults as CFO and M&A advisor for energy businesses in various stages of development ranging from start-ups to mature firms. Previously, Mr. Marshall served in an ‘operating partner’ role working with PE-backed portfolio companies on behalf of Luther King Capital Management. Mr. Marshall began his career with PwC in New York and has 12+ years of experience in M&A, financial management, accounting/controls, and board-level leadership. Mr. Marshall earned Masters and Bachelors degrees in Accounting from Texas A&M University and earned his MBA from Rice University.

Alvin Hosking, Geosciences

Mr. Hosking has 40+ years of domestic and international experience in the acquisition, processing, and interpretation of 2D and 3D seismic data. He is the author of “Static Corrections” which is widely used today in the processing and interpretation of seismic data. Mr. Hosking has expertise in generating and screening prospects and developing oil and gas fields throughout North America.

Hung Bui, PE Senior EOR Manager

Mr. Bui is a registered Petroleum Engineer from Penn State University with 30+ years of experience modeling, designing, and developing reservoirs for gas storage throughout North America on behalf of ANR Gas Storage Company, Coastal Corporation, CNG, El Paso Gas, TGP and Trans Canada. Mr. Bui has extensive experience designing reservoirs for maximum injection and withdrawal rates and liquid recovery. Mr. Bui is an advocate of new technology and reservoir modeling and simulation software and was the first to use underbalanced drilling and high-angle wellbores with spurs in the development of gas storage reservoirs. Mr. Bui is proficient in maximizing reservoir capacity.

Industry Overview

7

Problem: Stranded oil

Primary Production

When oil is discovered in a new reservoir, typically only 25% of the discovered oil reserves can be extracted with traditional drilling and extraction methods, called ‘primary production.’

Secondary & Tertiary Production

In order to recover additional crude oil from an oil reservoir, a number of ‘secondary’ and ‘tertiary’ production methods have been developed to mobilize crude oil trapped in rock formations and to re-pressurize the reservoir by replacing the volume of gas and oil extracted during primary production.

‘Secondary production’ typically refers to water floods, and ‘tertiary production’ typically refers to gas and steam floods.

The most effective tertiary method of Enhanced Oil Recovery is CO2 gas flooding. The key benefit of CO2 gas is that it is ‘miscible’ with crude oil; under pressure conditions, CO2 gas molecules combine with the crude oil, swell the oil and lower the viscosity pressure.

CO2 gas Injection has been successfully used for over 60 years in the very large oil fields located in Texas, Kansas, Oklahoma, Michigan, Louisiana, Mississippi, Wyoming and Oklahoma. CO2 projects are financially sound and represent some of the most profitable projects for companies like Kinder Morgan, Anadarko, Merit, Denbury and Whiting.

8

Historical solution: CO2 (gas) flooding

9

The chart below shows a typical result for gas flooding; this project is in the Salt Creek reservoir of Wyoming.

After six months of gas injection, the field produced 800 bopd. After one year, the field produced over 2,000 bopd.

EOR can double the recoverable oil reserves within most oil fields.

Problems with CO2 flooding: Transportation costs and supply

CO2 flooding is restricted to fields where large quantities of CO2 can be transported by pipeline from natural or industrial sources. Pipelines are costly with capital expenses reaching hundreds of millions of dollars.

10

Due to the cost of transporting CO2, only the largest oil fields in certain geographic areas will be developed. The capital required for CO2 flooding, as well as the scarcity of natural or industrial sources of CO2, results in a significant gap in the industry’s ability to optimize crude oil production in the world’s known reserves.

The Jackson Dome in Eastern Louisiana is the only natural source of CO2 east of New Mexico. In 1999, Denbury purchased the reservoir for enhanced oil recovery. Denbury has since built 1,100 miles of pipeline in Louisiana, Mississippi, and Texas to transport CO2 for gas flooding projects at a total cost of $2.2 billion .

Fossil Bay solution: Portable exhaust gas

Combustion gas is comprised of approximately 13% CO2 and 87% Nitrogen.

Researchers at Louisiana State University compared exhaust gas to pure CO2 in simulated conditions and found that exhaust gas performs significantly better than pure CO2 in the recovery of crude oil.

11

Combustion gas from a standard internal combustion engine provides an ideal gas for enhanced oil recovery.

In a pure CO2 flood, CO2 combines with oil under pressure, increasing the volume of oil and reducing viscosity.

Exhaust gas provides increased oil volume, reduced viscosity, and pressure-induced drive – without adding water.

This allows the oil to flow more freely towards the producing well. However, CO2 does not provide drive. In a pure CO2 flood, gas injection is followed by water (WAG, Water And Gas) which provides pressure and drive to push the oil

towards a producing well.

The 13% CO2 separates from the Nitrogen and combines with the oil under pressure, providing the needed swelling, lowering viscosity, and increasing oil flow.

The 87% Nitrogen gas rises to the top of the reservoir, providing a pressure source which is more effective than water at driving oil towards a producing well.

Evolution of exhaust gas as EOR solution

In the 1960s, exhaust gas was used in a number of projects. For example, the Spring Hill Field in Kentucky increased monthly oil production from 100 barrels per month to over 5,000 barrels per month after four months and a total of 8 million cubic feet of exhaust gas injection.

A critical step in using exhaust gas for EOR is post-production processing: drying the combustion gas, cooling it, and pressurizing it for injection. Without the drying step, loose water molecules in the gas create carbonic acid, which is a corrosive substance, damaging a well’s casing.

Exhaust gas production lost favor because the original equipment did not have the ability to effectively produce very large volumes of gas and deliver the post-production capacity (non-corrosive) needed to economically use the gas for injection.

12

Exhaust gas was initially promising but held back by technology. New technology allows effective use of exhaust gas for EOR.

Weatherford International owns the technology IP needed to produce very large quantities of pressurized exhaust gas for Enhanced Oil Recovery.

The system has been built, the gas output is fully characterized, and the equipment is field-ready. Exhaust gas volume and pressure are expandable to meet most gas injection requirements.

Fossil Bay Energy has negotiated an exclusive contract with Weatherford International.

Mobile Injection Gas Equipment

Gas Assisted Gravity Drainage with Horizontal Wellbores

Gas Assisted Gravity Drainage with horizontal wellbores will increase reservoir exposure, resulting in greater injection and production rates. Horizontal wellbores are essential for maximum oil recovery.

Nitrogen Drive

Horizontal wellbores

13

Oil & CO2 Under Pressure

Case study: Block 31, exhaust gas pioneer

Block 31 was discovered in the Permian Basin by Atlantic-Richfield in 1945. Estimated OOIP was 300 million boe with pressure exceeding 4,000 psi; however, the

reservoir rock was quite impermeable, around 1 md. Consists of three reservoirs: upper, middle, and lower.

Major reservoir (middle) is at depth of 8,500 ft with a net pay zone averaging 170 ft.

Porosity is intercrystalline and averages 15%. Initial well rates were essentially zero, and no oil was extracted under primary or

secondary methods. In 1949, Atlantic-Richfield began compressing and injecting natural gas from a nearby

source into Block 31, and production finally commenced under this revolutionary tertiary method.

By 1965, cumulative production from Block 31 approached 90 million boe. In 1966, to avoid using marketable natural gas, Atlantic-Richfield developed

a system to inject flue (exhaust) gas from a nearby processing plant. Production peaked at 20,000 bopd from the field in 1978 but slid steadily to

2,500 bopd in 1998 with average production per well of 15 bopd. Projected ultimate recovery through gas flooding is greater than 65% of

OOIP; to date, about two-thirds of the ultimate oil recovery has been produced.

14

Case study: Springhill Grove exhaust gas projects

The Springhill Grove field was discovered in 1958, and the two wells produced 1-2 bopd. In 1961, the operator bought an 80 mcfd Exhaust Gas Processor (EGP), and production increased to 6 bopd. In 1964, the field was sold, and the new operators employed additional EGPs for a total of 200 mcfd and started injection.

Within four months, the Springhill Grove field was producing at rates over 5,000 bopm. The offsetting Boswell-Walker Leases saw production increases from 150 bopm to 1,300 bopm by virtue of the exhaust being

injected in the Hart Lease. In 1964, a full scale development was initiated on this lease which produced 54% of the OOIP using Exhaust Gas.

N2

15

Competitive Landscape

16

Competing EOR methods: Water flooding

Water injection wells are used both onshore and offshore to increase oil recovery from an existing reservoir.

Water is injected to support reservoir pressure and sweep oil from the reservoir and push it towards a production well.

Normally, only 25% of the oil in a reservoir can be extracted; water injection often increases oil recovery by 8-12%.

Water floods are typically inexpensive but slow in affecting incremental oil recovery.

17

Competing EOR methods: Steam injection

Steam injection is the most common method of extracting heavy crude oil. It is considered an EOR method and is the main type of thermal stimulation used in heavy oil reservoirs.

There are several forms of steam injection: the two dominant methods are Cyclic Steam Stimulation and Steam Flooding. Both methods are most commonly applied to oil reservoirs which are relatively shallow and contain crude oils which are very viscous at the temperature of the native underground formation. Steam injection is widely used in the San Joaquin Valley of California (USA), the Lake Maracaibo region of Venezuela, and the oil sands of northern Alberta (Canada).

18

Competing EOR methods: Carbon sequestration (coal-fired)

Carbon sequestration is a potentially-attractive method of EOR which involves the use of flue gas from coal-fired power plants for CO2 gas flooding. While promising, flue gas produced in this manner is an imperfect tool: there is not yet an economical way to remove H2S and NOX from the emissions. Also, transporting the gas is still a challenge due to the distance between power plants and oil reservoirs.

A number of emerging projects are connected to new coal gasification power plants located near oil reservoirs. Coal gasification is a more expensive and energy-intensive process but eliminates the emissions and, thereby, the need for post-processing the gas to remove contaminants. These projects are also designed specifically to deliver gas to oil fields which makes transportation more tenable. Since these projects require billions of dollars in capital and years to complete, they are only feasible for very large oil fields.

19

EOR industry leaders

A number of major international companies have ventured heavily into EOR projects. These companies have the capital resources to exploit new opportunities and the reserves in place to develop significant projects:

BP Chevron ConocoPhillips ExxonMobil

Non-major leaders in the EOR Industry include the following: Denbury - CO2 , developing projects Kinder Morgan - own fields, supply and transport CO2 Apache - own fields, purchasing CO2 Whiting - own fields, purchasing CO2 Anadarko - own fields, purchasing and developing its own source of CO2 Merit - own fields, purchasing CO2 Occidental Chemical Company - 350,000 barrels from EOR in Calgary and California

These companies are invested primarily in traditional CO2 flooding methods. Fossil Bay plans to partner with oil producing companies like these on mobile exhaust gas flooding projects. In order to protect market position, FBE will invest in extending and deepening its intellectual property position around exhaust gas EOR.

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Market Opportunity

21

Domestic and Global Oil Markets

Domestic and Global Oil Reserves

The DOE and ARI estimate that approximately 72 billion barrels of reserves hold EOR potential in the United States alone. The United States proven reserves are 200 billion barrels with another 1,130 billion barrels in place.

Globally, it is difficult to estimate proven reserves since the data is highly political and closely-held. The US Energy Information Administration estimated 1.7 trillion barrels of global proven oil reserves in 2014.

The United States produces 2.3 billion barrels of oil annually while the global oil industry produces 32 billion barrels of oil annually.

United States Domestic Market

In the United States alone, there are roughly 225,000 crude oil wells in production with 1,330 billion barrels oil in place: 200 billion recovered and 200 billion stranded.

Of the 230,000 crude oil fields in the United States, Fossil Bay estimates that 114,805 have geologic merit and are potentially addressable for mobile gas flooding.

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Initial development focus: Michigan Basin

The Michigan Basin will be the initial developmental region. Fossil Bay currently has two pilot projects engineered and in the final permitting process in the Southern Niagaran Reefs.

Fossil Bay has Options on other reservoirs and will pursue acquisition of plugged and abandoned reservoirs throughout the Northern and Southern Reef Trends.

These reefs are some of the best reservoirs for Gravity Assisted Gas Injection EOR due to certain reservoir properties: thick pay columns, impermeable cap seal, compact size, low primary recoveries, and highly-dipping structure.

Fossil Bay has identified over 200 reefs in Michigan which meet the EOR criteria, representing over 150 million barrels of oil. Over 75 of those reefs are plugged and abandoned and could be obtained through direct leases. The remaining producing fields can be obtained through Joint Venture agreements with small independents.

Pure CO2 flooding has been successful in a handful of Michigan reefs with production rates as high as 1,200 bopd. However, pure CO2 flooding in Michigan would be limited to less than 10 total projects due to the lack of scalable CO2 supply and the costly infrastructure required to move the gas.

Fossil Bay’s mobile exhaust gas process is the only known process which is scalable enough to have a major impact on the recovery of stranded oil in Michigan and other North American basins.

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Michigan Basin: Brief EOR history, attractive Niagaran characteristics

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EOR in Michigan

Historic oil production primarily from Ordovician, Silurian and Devonian carbonates.

Cumulative oil production exceeds 1.2 billion boe.

Most fields produced through primary phase only.

A few dozen water floods have been mostly successful. Water flood production nearly equals primary production in some fields.

ANR-designed gas storage operations have recovered long-term liquids at rates upwards of 7,000bpd from the Niagaran Reefs.

CO2 flooding began in Niagaran Reefs in 1996; only three fields developed to date due to limited pipeline access.

Completely sealed vertically & laterally by evaporitic lithologic sequence.

Readily identifiable by seismic.

Ideal for gas re- pressurization.

Dover 33 CO2 – EOR project Michigan

High Angle Production Well

Cased Hole Completion

Injector Well

Crestal position Horizontal Production well

Open Hole Completion

1974 1978 1982 1986 1990 1994 1998 2002 2006

10

100

1,000

10,000

100,000

Time

Month

ly P

roductio

n R

ate

s

Oil Production (bbl)

447 MBO

1, 280 MBO Primary Recovery

447 MBO CO2 Flood Recovery to date

2.2 Bcf to reach MMP – 9 months

Northern Reef Trend

Over 650 Separate Reefs

390 Million boe and 2.2 TCF gas produced

28% average primary recovery

Only a limited number of waterflood attempts

Thickness 150 to 700 ft

Average Porosity (Range) 7% (3 to 18%)

Average Permeability (Range) 12 md (0.1 md to 8 darcies)

Oil Gravity 40º to 42º api on average

Average Reservoir Temperature 100º to 120º F

Oil Formation Volume Factor 1.2 to 1.6

Lithology Dolomite and/or Limestone

Average depths to top of reservoirs 3600 to 6000 ft

Key Engineering Properties - Northern Trend

Bottom Line – Spectacular Tertiary Recovery and Sequestration Targets

Michigan Basin: Typical project economics

A small to medium-sized reservoir with 2 million barrels of proven reserve will require approximately $5 million in upfront capital for all project development expenses.

Direct project development expenses include the following:

Seismic, Geology, Geophysics, Engineering

Drilling a new horizontal production well

Converting the existing production well into a horizontal gas injection well

Leasing the exhaust gas equipment

Provisioning fuel required to run the equipment during the re-pressurization phase

Ongoing recirculation and reinjection of gas extracted as a byproduct of the oil production

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Michigan Basin: Typical project economics

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Pure CO2 projects range in yield from 17% to 34% of original oil in place. Fossil Bay estimates a 25% yield over 5 years for total gross proceeds of $25 million at $50 oil.

Ave MI Reef Mid-Case

Year Assumptions 0 1 2 3 4 5 Total

Income

Oil In Place Barrels 2,000,000

Oil in Place Recovery 25% - 130,293 121,757 97,957 84,643 65,350 500,000

Price per Barrel $ 50

Gross Proceeds $ - $ 6,514,627 $ 6,087,861 $ 4,897,869 $ 4,232,133 $ 3,267,509 25,000,000

Expenses

Project Cost

Work Over $ 75,000 $ - $ - $ - $ - $ - $ -

Prodocer Well

Completion $ 275,000 $ - $ - $ - $ - $ - $ -

Project Development $ 100,000 $ - $ - $ - $ - $ - $ -

Rotary Rig $ 1,300,000 $ - $ - $ - $ - $ - $ -

Injection Gas $ 1,430,000 $ - $ - $ - $ - $ - $ -

Operating Cost $ 200,000 $ 200,000 $ 200,000 $ 200,000 $ 200,000 $ 1,000,000

Total Project Cost $ 3,180,000 $ 200,000 $ 200,000 $ 200,000 $ 200,000 $ 200,000 $ 4,180,000

Stakeholder Carry

Mineral Rights Owner 20% $ 1,302,925 $ 1,217,572 $ 979,574 $ 846,427 $ 653,502 $ 5,000,000

Severance Tax 4% $ 260,585.06 $ 243,514 $ 195,915 $ 169,285 $ 130,700 $ 1,000,000

Well Operator 0% $ - $ - $ - $ - $ - $ -

Total Expense $ 3,180,000 $ 1,763,510 $ 1,661,087 $ 1,375,489 $ 1,215,712 $ 984,202 $ 10,180,000

Net Proceeds $ (3,180,000) $ 4,751,116 $ 4,426,775 $ 3,522,381 $ 3,016,421 $ 2,283,307 $ 14,820,000

General Partner

Carry 20% $ 950,223 $ 885,355 $ 704,476 $ 603,284 $ 456,661 $ 3,600,000

Management Fee 0% $ - $ - $ - $ - $ - $ -

Proceeds $ 950,223 $ 885,355 $ 704,476 $ 603,284 $ 456,661 $ 3,600,000

Limited Partners

Proceeds $ (3,180,000) $ 3,800,893 $ 3,541,420 $ 2,817,905 $ 2,413,137 $ 1,826,646 $ 11,220,000

IRR 106%

Cash Multiple 4.5x

Partnering with oil production companies

Fossil Bay will partner with existing well owners and operators to increase the ultimate recovery of oil from their pressure-depleted reservoirs. As a general rule, gas flooding methods are geologically appropriate for roughly 50% of conventional oil reservoirs.

Fossil Bay’s initial primary market of Joint Venture partners will be small and medium-sized oil production companies that operate reservoirs with between 1 million and 5 million barrels of original oil in place (OOIP).

Fossil Bay Energy is essentially a project finance, engineering, and management company.

Fossil Bay is partnering with existing oil producers who will be highly motivated to increase the yields on expiring and depleted holdings. FBE production partners will have detailed geology, engineering, and production data for each field - reducing the cost and risk associated with choosing projects.

Project drilling and completion costs are contained at the operating company level and are funded by Fossil Bay’s partners with whom FBE will share the risk and reward for each project. The resources needed to mobilize a project are industry standard and readily available in any oil producing region.

The key activities and related expenses for Fossil Bay will include the following: Project Origination: recruiting, educating, and managing relationships with a highly-fragmented group of independent oil producers

as well as large production companies. Project Engineering: the key technical risk for this opportunity is correctly selecting projects with economic merit and accurately

producing the geologic and engineering analysis needed to spec drilling and injection operations. Project Finance: the total market opportunity will potentially require billions of dollars in capital. Best-in-class financial controls will

be essential to success. Project Management: the opportunities for enhanced oil recovery span the globe. Capitalizing on these opportunities, while at the

same time ensuring operational control and efficiencies, will be an extremely complex and difficult task. Fossil Bay plans to start locally and scale in a controlled way, establishing strong local partnerships in order to distribute responsibility to parties with working knowledge for each new region.

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Six-project portfolio: Projected cash flow and project timeline

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TASKS Sept Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar

Pilot Project

Second Project

Third Project

Forth Project

Fifth Project

Sixth Project

Key

Eng, Land & Legal Evaluation PeriodEvaluation Per.

Drilling Operations Production

Injection Period

Investors’ Net Cash Flow

Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8

Project 1 (1,880,000) 1,476,175 1,371,612 1,080,047 916,932 680,586

Project 2 (1,980,000) 1,476,175 1,371,612 1,080,047 916 819,373

Project 3 (3,180,000) 3,800,893 3,541,420 2,817,905 2,413,137 1,826,646

Project 4 (3,180,000) 3,800,893 3,541,420 2,817,905 2,413,137 1,826,646

Project 5 (3,180,000) 3,800,893 3,541,420 2,817,905 2,413,137 1,826,646

Project 6 (3,180,000) 3,800,893 3,541,420 2,817,905 2,413,137 1,826,646 Net Cash Flow to Investors

(7,040,000) 393,243 10,706,430 15,861,732 12,508,215 10,970,784 6,066,429 1,826,646 51,293,479

IRR 90.0%Cash Multiple 4.1x

2 Year CAPEX with Net Revenue after Op. Cost, Royality, State Taxes

Pilot Project 1: Cigna 1-23

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Overview: Cigna 1-23

Cigna 1-23 is a 25 acre Niagaran Reef having produced 176,000 boe since 1994; the well is located in Livingston County, Michigan and has recovered 18% of the OOIP.

The Cigna 1-23 had 1779# BHP at discovery, 140 ft. of net oil pay with an average of 6.5% porosity.

OOIP was estimated between 861,000 and 1,000,000 boe; CO2 floods could reasonably yield 18-32%.

Fossil Bay estimates OOIP of 861,000 boe and projects 25% additional oil recovery through mobile exhaust gas EOR.

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0.0

500.0

1000.0

1500.0

2000.0

19

11

81

27

13

61

45

15

41

63

17

21

81

19

01

99

11

08

11

17

11

26

1

Historic Prod -vs- Pressure Decline

Reservoir Pressure(PSIA)

OIL Prod. Rate(STB/DAY)

Cigna 1-23: Prediction of reservoir performance

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The simulation model and data developed in the history match analysis were used to design and forecast field performance that could achieve the objective target rate. To enhance the mixing of injected flue gas of N2 and CO2 with the residual oil in place, the compositional model was used for the prediction analysis. A compositional sample of the reservoir was also constructed based upon data from various reservoirs in the reef trend. One new horizontal well would be completed in the lower zone as the producing well with a spur leg extending into additional unproduced areas of the reservoir. The existing vertical production well will be converted into the injection well. The new horizontal producing well would have approximately 1,200 feet of open-hole exposure to the reservoir. Special procedures should be used to complete the producer as an upward (toe up) slanted horizontal well. Prediction analysis indicates that oil production could begin after three months of injection. Cumulative injection of 90 MMscf would raise reservoir pressure to approximately 1,200 psi. Field production could duplicate the primary volume in two-to-three years. However, the CO2 concentration in the produced vapor would be less than 4% over time, and, occasionally, a fresh patch of flue gas may be necessary to enhance oil mobility.

Cigna 1-23: EOR financial projections

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Cigna 1-23 Mid Case


Income

Oil In Place Barrels 980,370



Gross Proceeds $ - $ 2,810,168 $ 2,626,077 $ 2,112,759 $ 1,825,585 $ 1,409,482 10,784,070

Expenses

Project Cost

Work Over $ 72,500 $ - $ - $ - $ - $ - $ -

Prodocer Well Completion $ 182,000 $ - $ - $ - 8cv zv $ - $ -


Rotary Rig $ 825,500 $ - $ - $ - $ - $ - $ -

Injection Gas $ 650,000 $ - $ - $ - $ - $ - $ -

Operating Cost $ 150,000 $ 150,000 $ 150,000 $ 150,000 $ 150,000 $ 750,000


Stakeholder Carry

Mineral Rights Owner 25% $ 702,542 $ 656,519 $ 528,190 $ 456,396 $ 352,371 $ 2,696,018

Severance Tax 4% $ 112,406.70 $ 105,043 $ 84,510 $ 73,023 $ 56,379 $ 431,363

Well Operator 0% $ - $ - $ - $ - $ - $ -

Total Expense $ 1,880,000 $ 964,949 $ 911,562 $ 762,700 $ 679,420 $ 558,750 $ 5,757,380

Net Proceeds $ (1,880,000) $ 1,845,219 $ 1,714,515 $ 1,350,059 $ 1,146,165 $ 850,732 $ 5,026,690

General Partner

Carry 20% $ 369,044 $ 342,903 $ 270,012 $ 229,233 $ 170,146 $ 1,381,338

Management Fee 0% $ - $ - $ - $ - $ - $ -

Proceeds $ 369,044 $ 342,903 $ 270,012 $ 229,233 $ 170,146 $ 1,381,338

Limited Partners

Proceeds $ (1,880,000) $ 1,476,175 $ 1,371,612 $ 1,080,047 $ 916,932 $ 680,586 $ 3,645,352

IRR 62%

$ 5,525,352

Pilot Project 2: State Cleon 2-13

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Overview: State Cleon 2-13

The Cleon 13 field was discovered by Federal Oil in December 1993 in Cleon Township, Manistee County, Michigan.

The St Cleon 2-13 well penetrated the Brown Niagaran reef at a True Vertical Depth (TVD) of 5,609 feet and encountered the Gray Niagaran formation at a TVD of 6,034 feet.

From the well log analysis, the reservoir net pay extended from the top of the Brown Niagaran to approximately 5,965 feet TVD and a net pay of 356 feet.

The discovery field data indicated that the Cleon 13 field is an under saturated oil reservoir. The initial produced oil has an estimated gravity at about 42 degrees API, and the separator gas gravity was about 0.6.

Bottom hole pressure was 2,380 at 5,907 feet. In December 1996, the original perforation interval was squeezed, a casing window was milled, and the well was completed with a lateral open hole from 5,879 to 6,512 feet.

The first lateral extended 660 feet south and 400 feet west of the original well location at an average depth of 5,040 feet TVD.

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State Cleon 2-13: Production History

The production history of the field indicated that the original 21 feet perforation interval and the perforations added in October 1995 produced 124.6 Mbbls of oil and 242 MMscf of gas from December 1994 to December 1996.

After the well was recompleted with the lateral, production increased for a short period, then fell off. The reservoir produced an additional 62.3 Mbbls of oil and 66MMscf of gas since that time and is currently producing at a rate of 5 bopd. This reef recovered approximately 22% of the Original Oil in Place.

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The Cleon 13 project will utilize the existing wellbore as the injector well, and a new well will be drilled to act as the producer. The Injection Phase is expected to last approximately 90 days. Once the reservoir is partially re-charged, a shut-in soaking period will take place before the well is returned to production.

State Cleon 2-13 Reservoir: EOR production profile

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State Cleon 2-13: EOR financial projections

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Cleon 13 Mid Case


Income

Oil In Place Barrels 980,370



Gross Proceeds $ - $ 2,810,168 $ 2,626,077 $ 2,112,759 $ 1,825,585 $ 1,409,482 10,784,070

Expenses

Project Cost

Work Over $ 75,000 $ - $ - $ - $ - $ - $ -

Prodocer Well Completion $ 290,000 $ - $ - $ - 8cv zv $ - $ -


Rotary Rig $ 825,000 $ - $ - $ - $ - $ - $ -

Injection Gas $ 650,000 $ - $ - $ - $ - $ - $ -

Operating Cost $ 150,000 $ 150,000 $ 150,000 $ 150,000 $ 150,000 $ 750,000


Stakeholder Carry

Mineral Rights Owner 25% $ 702,542 $ 656,519 $ 528,190 $ 456,396 $ 352,371 $ 2,696,018

Severance Tax 4% $ 112,406.70 $ 105,043 $ 84,510 $ 73,023 $ 56,379 $ 431,363

Well Operator 0% $ - $ - $ - $ - $ - $ -

Total Expense $ 1,990,000 $ 964,949 $ 911,562 $ 762,700 $ 679,420 $ 558,750 $ 5,867,380

Net Proceeds $ (1,990,000) $ 1,845,219 $ 1,714,515 $ 1,350,059 $ 1,146,165 $ 850,732 $ 4,916,690

General Partner

Carry 20% $ 369,044 $ 342,903 $ 270,012 $ 229,233 $ 170,146 $ 1,381,338

Management Fee 0% $ - $ - $ - $ - $ - $ -

Proceeds $ 369,044 $ 342,903 $ 270,012 $ 229,233 $ 170,146 $ 1,381,338

Limited Partners

Proceeds $ (1,990,000) $ 1,476,175 $ 1,371,612 $ 1,080,047 $ 916,932 $ 680,586 $ 3,535,352

IRR 57%

$ 5,525,352

Investment Opportunity

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Investment Opportunity

We are currently raising funds for Fossil Bay Energy LLC to execute its initial Exhaust Gas EOR Projects. The first $6 million of the planned $30 million raise will fund our first two projects in southern Michigan. The initial projects are fully engineered and will be ready to begin the 1st quarter of 2017.

The Funding Parties shall have the right to participate with Fossil Bay Energy in future projects within the State of Michigan. Participation Rights outside of Michigan shall be negotiated by the parties. All Participation Terms and Conditions shall be mutually agreed upon by all parties and detailed in a legally-binding agreement.

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fossil bay energy - investment opportunity cim - september 2016 - bmm v3

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