PetroFrontier Corp (PFC)

[eom7]

1. What hydraulic stimulation has occurred in the Southern Georgina Basin? Were they successful?

A nine stage hydraulic stimulation of the MacIntyre-2H (EP 127) well was successfully performed during the first week of September.

A 10 stage hydraulic stimulation of the Owen-3H (EP 104) well was successfully performed during the first week of October.

2. What initial results have these two hydraulic stimulations yielded?

a. At Owen-3H?

PetroFrontier is very encouraged by the low fluid injection pressures and high injection rates evident during the stimulation of Owen-3H. These high injection rates indicate the presence of natural permeability due to natural fracturing and/or significant porosity within the Lower Arthur Creek and Thorntonia Formations.

Log data and core samples have been obtained and appear positive, confirming the existence of oil in the Lower Arthur Creek and Thorntonia Carbonate Formations. The rock mechanical testing and core plug petrophysics are currently underway and definitive results are expected by mid-November.

The formations at Owen-3H may not be as tight as PetroFrontier's original reservoir modelling of the well assumed. In order to achieve optimal frac fluid recovery and production flow rates, PetroFrontier will be utilizing a higher capacity jet pump instead of a pump-jack as originally planned. This piece of equipment has come from North America and is capable of substantial flow rates, and will significantly increasing fluid productivity at the well site.

Like the MacIntyre-2H well, Owen-3H has now encountered nuisance levels of hydrogen sulphide in the initial flow back of the stimulation fluid. PetroFrontier was able to accelerate the purchase and assembly of the hydrogen sulphide resistant equipment planned for MacIntyre-2H and has installed it at the Owen-3H well. This testing has now commenced and is anticipated to take up to 6 weeks depending on weather, equipment reliability and the nature of the recovered fluids.

b. At MacIntyre-2H?

After recovering approximately one-third of the hydraulic stimulation fluid at the MacIntyre-2H well, traces of what is believed to be biogenic hydrogen sulphide gas, produced from naturally occurring organisms in the completion fluid, were detected and the well had to be suspended. This issue resulted in unforeseen minor operational delays only - the prospectivity of this well remains totally intact.

The integrity of the well is not in question. The testing equipment under contract and in hand is appropriately rated for service with low levels of hydrocarbon sulfide. However, additional testing equipment required for "sour" water handling had to be assembled. Flow-testing of MacIntyre-2H is expected to resume in the near future after the flow-testing of the Owen-3H well has been completed depending on weather, equipment reliability and the nature of the recovered fluids.

3. What is biogenic hydrogen sulfide (H2S)? How can it be treated?

Biogenic H2S is created through a chemical process in water that contains sulfate reducing bacteria (SRBs) that is believed to have been injected into the well. SRBs induce chemical changes in the presence of naturally occurring sulfates to form H2S, via a complex series of biochemical reactions..

In PetroFrontier's case, biogenic H2S is dissolved in the water that is being recovered during flow-testing (in the load fluid, not the formation fluid as of yet). No H2S was encountered while drilling or coring. PetroFrontier is adding a chemical H2S scavenger to the produced fluid, which chemically alters the H2S and thereby essentially eliminates it. PetroFrontier and its contractors have engineered a system for the continuous injection of the scavenger into the water as it exits the wellhead, so that at the storage tanks, it is H2S free.

These chemicals, equipment and operating practices are relatively common in Canada - not so much in Australia.

PetroFrontier has taken an exemplary lead in dealing with the safety issues that can be associated with H2S, which is relatively uncommon in Australia. PetroFrontier holds workplace safety in high regard. As such, senior management has brought in expertise from Canada to supervise these operations to ensure the ongoing safety of all stakeholders.

Scavenger: a substance added to a mixture to remove or inactivate impurities, can be a fluid or a liquid.

4. What happened at Baldwin-2Hst1? Why couldn't the program be completed? What impact did it have? Is further stimulation planned?

As the hydraulic stimulation program of the Baldwin-2Hst1 well began, a casing failure occurred at a depth of approximately 102 metres. As a result, PetroFrontier was unable to continue with the hydraulic stimulation program. Baldwin-2Hst1 was hydraulically stimulated down casing cemented into the surrounding rock formations. The hydraulic stimulation treatment pressure was anticipated to be less than 5000 psi, while the casing was rated to 7000+psi. However, the casing failed at 4000psi, which confirms that there was a mechanical problem with the casing itself.

This is a well construction problem, not a well completion problem. This issue resulted in unforeseen operational delays only - the prospectivity of this well remains totally intact.

As expected, the multiple casing design Petrofrontier used to construct the well protected the shallow aquifers. The well was safely suspended and PetroFrontier plans to carry out the relatively simple remedial work to repair this well so that the planned hydraulic stimulation program can be completed. PetroFrontier and Statoil are currently evaluating the availability and costs of mobilizing a hydraulic stimulation crew for the completion of this well only.

Please see question 7 for further details.

5. When will Owen-3H be flow tested?

PetroFrontier has just commenced an extended flow-test at Owen-3H and it is anticipated to take up to 6 weeks depending on weather, equipment reliability and the nature of the recovered fluids.

6. What is the potential at Owen-3H?

Between 1962 and 1991 a total of 18 wells were drilled in the Southern Georgina Basin (distributed at less than one well per 5,500 sq. km), with only eight of those on PetroFrontier's lands. All wells were drilled with slim-hole mining rigs and were fully cored and logged. There were numerous high background gas readings, gas and oil shows, and oil staining in cores in addition to live oil bleeds. The Owen-3H well is a continuation of the potential shown by this past activity. PetroFrontier has taken this data one step further by bringing new and enhanced North American extraction technologies to Australia in order to further the development and, ultimately, prove the economic viability of this massive and unexplored basin.

During drilling of the horizontal section at Owen-3H, numerous positive hydrocarbon indicators were observed including: oil staining, milky yellow fluorescing cut, strong gas recordings of C1 to C5, petroliferous odour and oil spots in the mud at the shaker. Core evaluations at Owen-3H are ongoing and PetroFrontier is encouraged by the initial assessment.These cores seeped oil upon retrieval and had extensive fluorescence throughout.

Milky yellow fluorescing cut: when oil is exposed to UV light it fluoresces (glows) and the lighter the color the lighter the oil grade.

7. What could PetroFrontier's capital expenditure program look like in 2013?

This program and the nature of the planned activities will address ongoing exploration permit requirements and will be significantly influenced by results from the Phase 1 - 2012 capital expenditure program. PetroFrontier, Statoil and Baraka will begin discussions in November regarding the Phase 1 - 2013 capital expenditure program.

Options that are being considered are: seismic acquisition, stratigraphic core hole drilling campaign, drilling vertical and/or high angle wells followed by optional hydraulic stimulations along with assessing the availability and costs associated with the remediation and completion of the Baldwin-2Hst1 well.

8. What are the onshore operational challenges PetroFrontier experiences working in the Northern Territory, Australia?

It is important to recognize that PetroFrontier's exploratory lands are located many kilometres (2000 km in some cases) from any other existing oil and gas operations and from major service and supply centres, resulting in significant operational challenges with logistics, equipment and manpower. High costs, and the limited availability of oilfield services and equipment make Australia's oil and gas fields more difficult to develop than those in North America.

PetroFrontier must spend a considerable amount of lead time co-ordinating operations so that all equipment and people are available and onsite at the appropriate time. Therefore, in order to procure all necessary equipment and personnel, PetroFrontier must enter into minimum commitment contracts which results in considerable standby costs. Furthermore, field operations must cease when the public roads are closed because of wet conditions.

PetroFrontier has an extremely competent operations team that is making significant efforts to overcome these issues and is continuously improving its local knowledge and ultimately its ability to react to unforeseen circumstances and to better foresee the true cost of delivery.

9. What is PetroFrontier doing to mitigate weather related delays moving forward?

In the current exploration and evaluation stage the use of lighter more portable equipment, helicopters and the pre-planning of equipment and supplies are all being used to help mitigate rain delays. However, given circumstances of the closures of government maintained roads there are only very limited strategies to mitigate delays.

Weather related delays may be minimized at the development stage of operations by the concentration of well sites into a central area. Depending upon the capacity of the well site area, permanent producing infrastructure, pipelines, paved roads, permanent well developed camps and air support facilities would be necessary. The benefits to this next stage, when many more wells are drilled and stimulated, would be that the average cost of doing business in the outback of Australia would fall significantly as the benefits of economies of scale are realized.

Financial
1. What is the value of the Statoil deal compared to others in Australia?

Company

Basin

Company Farm-In

Date

A$ (Millions)

Potential
Working Interest To be Earned

Net Acres

(Millions)

Farm-out

(Millions)

$/acre

PetroFrontier

Georgina

Statoil

2012

210.0**

65%

12.2

7.9

27**



















Central Petroleum

Amadeus

Santos

2012

150.0

70%

19.0

13.3

11

New Standard Energy

Canning

Conoco

2011

109.5

75%

11.0

8.3

13

Falcon

Beetaloo

Hess

2011

57.5*

62.5%

5.1

3.2

18*

Buru

Canning

Mitsubishi

2010

152.0

50%

14.1

7.1

22

*USD - In addition, Hess can elect to continue to the next phase of the work program, which
includes conducting a five well program to explore and appraise the agreement area, beginning
in 2012. Hess will cover the full cost of this work program.
**USD

2. How much will be spent in 2012 and how much is left to complete the Phase 1 operations?

2012 Phase 1 - Statoil/PetroFrontier commitment: USD$50.0 MM

Projected amount to be spent in 2012 USD$35.0 MM

2013 - Balance of Phase 1 Capital Program: USD$15.0 MM

3. What are the estimated costs of the re-treatment of the H2S issue at MacIntyre-2H and repairing the casing failure for Baldwin-2Hst1? Will Statoil and Baraka finance these costs?

Our operations group are currently working on establishing estimates for these projects. PetroFrontier is the operator during Phase 1 and as such when appropriate will propose the operations as part of the work program and budget and will seek partner approval where necessary.

4. What requirements does PetroFrontier need to fulfill in order to have Statoil elect to move to Phase 2? Is there a timeline set for this announcement?

Phase 1 consists of a joint exploration program of US$50 million (with each of Statoil and PetroFrontier contributing US$25 million). At the end of Phase 1, Statoil will have the option to acquire 25% of PetroFrontier's working interest by reimbursing PetroFrontier for its US$25 million Phase 1 contribution and by committing to proceed with Phase 2.

Statoil has 120 days following the receipt of all Phase 1 data to elect whether or not it will exercise its option to proceed with Phase 2.

PetroFrontier expects to complete Phase 1 during 2013.

5. One of the challenges PetroFrontier has faced is its ability to precisely estimate operational costs. Why is that?

There is an overall lack of competition with many of the oil field services in Australia. This lack of competition results in very high operating costs and any delays or unforeseen operational challenges can result in substantial cost overruns. Furthermore, PetroFrontier's operations are located in a very remote area, which also increases the potential for higher than anticipated support costs. Our learnings in this area have not gone to waste and we are very diligent about continually improving our ability to predict project costs and to execute more efficiently.

Corporate
1. How involved is Statoil? Is Statoil continuing with the Phase 1 program? What staff is currently on site?

As per the PetroFrontier/Statoil Joint Venture agreement, PetroFrontier is the operator of the Phase 1 program. However, Statoil is informed of and participates in all operational decisions in Phase 1. Currently, Statoil has a Development Geologist, Drilling Engineer and a Community/Government Relations Specialist in PetroFrontier's Adelaide office.

2. What is the acceptable method of dissemination of material information for a Canadian issuer?

The timely disclosure policies of the TSX Exchanges state that material information must be disseminated through a news service that provides for wide and simultaneous national dissemination of the full text of news releases to the financial media and newspapers.

PetroFrontier operates in Australia but is listed under the TSX Venture Exchange only and is obligated to release material information as it becomes available, but is under no obligation to release monthly operational updates. PetroFrontier will continue to facilitate fair access to non-material information that serves the needs of all markets by posting it on its website in a timely manner.

http://www.petrofrontier.com/index.php?page=frequently_asked_questions